Shale gas and fracking: exploration for unconventional hydrocarbons

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Topical Perspective

Shale gas and fracking: exploration for unconventional hydrocarbons Iain C. Scotchman Statoil (UK) Ltd., 1 Kingdom Street, London W2 6BD, UK

A R T I C L E I N F O

A B S T R A C T

Article history: Received 17 September 2015 Received in revised form 30 August 2016 Accepted 1 September 2016 Available online xxx

Geological perspective and discussion of shale reservoired hydrocarbons (shale gas and shale oil) and the emotive process used to produce them, hydraulic fracturing or fracking in colloquial parlance, is timely, in view of the current debate on the potential for exploitation of shales in the UK. Fracking is a longstanding oil industry process which has recently allowed unconventional hydrocarbons to dominate much of the world oil industry. This is particularly so in the USA where their development has dramatically overturned the decline in domestic production, with the current attainment of near selfsufficiency in both oil and gas production. Exploration for, and production of, shale-reservoired hydrocarbons requires a very different approach and mind-set from that required for conventional oil and gas resources, as well as raising widespread concerns around environmental aspects of fracking. The aim of this paper is to discuss the geology of shale resources and the techniques developed for their exploration and exploitation and place the environmental issues in their geological, not socio-economic context. ß 2016 The Geologists’ Association. Published by Elsevier Ltd. All rights reserved.

Keywords: Shale gas Shale oil Fracking Hydraulic fracturing Unconventional hydrocarbons

1. Introduction The aim of this ‘‘Topical Perspective’’ is to objectively discuss the geological and technical aspects of the exploration and production of hydrocarbons from shales, including hydraulic fracturing (‘‘fracking’’). This is unashamedly presented from a hydrocarbon exploration geologist’s perspective and whilst the potential environmental issues and risks are outlined, this paper does not seek to fully examine or discuss these important topics which are ably and further discussed elsewhere (King, 2012; Zuckerman, 2013; Hester and Harrison, 2015; Stephenson, 2015; Kaden and Rose, 2015). It should be noted that this paper is derived and adapted from a fuller, previously published treatise on shale resources and their exploitation (Scotchman, 2014). In a world where the human race is ever more energy-hungry and dependent, sources of low carbon energy should be at a premium, particularly as Governments world-wide endeavour to limit carbon emissions and make the transition to renewable or nuclear energy sources. Natural gas is currently seen as a transitional energy source to displace high carbon energy sources such as coal or heavy oil. In the USA, the boom in shale-gas production over the last 10–15 years has hastened this process, displacing the previously high coal-burn for electricity generation. However, in the United Kingdom and much of Europe, potential for

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the exploration and development of shale gas resources is only occurring at a slow to virtually non-existent pace, due to a number of complex factors. While this can mostly be attributed to the widespread public concerns over the safety and potential environmental effects of the hydraulic fracturing (fracking) process required to produce gas from shale (Engelder, 2014), the lack of drilling activity, development of infrastructure, limited licencing and, importantly, the slow development of regulatory frameworks are also major factors. In the USA, shale gas (and shale oil) has been extracted extensively and has not only enriched both individuals and communities but has also been instrumental in reducing US carbon dioxide emissions by replacing much coal-fired electricity generation. In the UK the position is different as all hydrocarbons are owned by the state with a Government controlled hydrocarbon licensing system with devolved local authority planning controls on actual exploration activities (DECC, 2013). Nevertheless the potential for shale gas and shale oil production in the UK (and Europe) is clear, and it could play an important role in meeting rising energy demands in the face of rapidly declining internal UK production and reserves and the increasing need for imports. However, after an initial start in the mid-2000s, the possibility of hydrocarbon production from shales, as either shale gas or shale oil, has since been be met with widespread public opposition leading to moratoria and regulatory stagnation. Much has been made of the potential for poorly engineered and executed wells and fracking procedures to potentially result in gas

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leakage, contamination of ground-waters and minor earthtremors, based on largely unattributed Internet-sourced information with no rigorous scientific basis. However, scientific and engineering data collected on the many thousands of wells drilled for both shale gas and shale oil in the USA over the recent years indicates fracking is inherently safe and does not cause widespread environmental damage when properly engineered and executed (Hitzman et al., 2013; Engelder, 2014; Committee on Climate Change, 2016). The challenge therefore falls to both industry and Government to communicate this reality to the public, in the face of a vast array of incorrect information (e.g. The Times, 2015), spread uncontrollably on the internet and social media by opponents of the process to support their views. 2. Unconventional hydrocarbon resources – what are they? Until the mid-1990s, the world’s hydrocarbons were almost totally produced from porous and permeable rocks such as sandstones and limestones sealed in individual geological traps by shales or salt. These are now known as ‘‘conventional’’ hydrocarbon resources and the bulk of the known reserves in the world occur in these reservoirs. Unconventional hydrocarbon resources, as suggested by the name, are very different, although the actual hydrocarbons (oil and gas) are the same. Most unconventional hydrocarbon reservoirs occur in the same basins as conventional reservoirs, where they also form the source rocks for the ‘‘conventional’’ hydrocarbons and, potentially, the seal. A further key difference from conventional reservoirs is that unconventional hydrocarbons are trapped within the whole of the reservoir rock unit, due to its inherent very low or negligible permeability. Thus these resources are limited only by the stratigraphical extent of the reservoir and economic considerations, hence the need for delineating the most prospective areas with the best reservoir parameters and hydrocarbon content, the so-called ‘‘sweet spots’’. Indeed, shale reservoirs can cover very large areas, for example the US Marcellus Shale Formation extends over much of the state of Pennsylvania and adjoining areas of New York, Ohio, Kentucky and West Virginia. However, due to lateral

variations in lithology, mineralogy, organic-richness and thermal maturity, only areas of northern and south-western Pennsylvania and northern West Virginia contain economic volumes of shale-gas (e.g. Wang and Carr, 2012). By definition, unconventional hydrocarbons comprise oil and gas resources trapped in any ‘‘non-conventional’’ reservoir (i.e. not the porous and permeable sandstones and limestones which comprise ‘‘conventional’’ reservoirs), and encompass gas hydrates, shale gas, shale oil, coal-bed methane (CBM) and so-called ‘‘tight gas and oil’’ (reservoired in low permeability sandstones and limestones) (Fig. 1). However, in general, the term ‘‘unconventional hydrocarbons’’ has come to mean shale resources (shale gas and shale oil), both characterised by very low matrix permeability reservoirs with natural fractures, the former generally comprising organic-rich shales containing both free and adsorbed gas (Montgomery et al., 2005) (Fig. 2). Extraction of hydrocarbons from these rocks requires the creation of an artificially permeable reservoir using hydraulic fracturing of horizontal well bores drilled within the near-impermeable shale. 3. Hydraulic fracturing – what is it? Hydraulic fracturing, or ‘‘fracking’’, is a long established oil-field stimulation technique used since the late 1940s to increase the production of hydrocarbons from poor quality, low permeability (often known as ‘‘tight’’) reservoirs. The process involves the multistage injection of fluids, generally water, into the well-bore at sufficient pressure to fracture the reservoir rock by exceeding its fracture gradient. Surface equipment is used to pump hydraulic fracturing fluid (‘‘frack fluid’’) down-hole into the reservoir, which results in the formation of an artificial fracture network radiating out from the horizontal well-bore (Fig. 3). The fracturing fluid comprises 99.95% water as discussed below, the remaining fraction being proppant particles, usually quartz sand or ceramic material used to keep the fractures open after the injection process has ceased, and very small (0.05%) amounts of gels, friction-reducers, cross-linkers, and surfactants. These additives, commonly found in cosmetics, household cleaners and other similar products, are

Fig. 1. Geological sketch illustrating the various forms of unconventional hydrocarbon systems and their relationships to conventionally reservoired hydrocarbons, showing the relationship to thermal maturity as defined by the oil generation window (green line) and gas generation window (red line). CBM is coal bed methane.

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drilling for conventional oil and gas reservoirs across the USA, from Pennsylvania and Ohio south-westwards to Texas, requiring the early drillers to wait several days for these formations to de-gas: later wells have required expensive steel casing to contain the generally over-pressured gas. It was not until the 1980s, with indigenous conventional-reservoired gas supplies declining, that in the USA these were considered as a potential resource (Henry, 1982; Zielinski and McIver, 1982; Hill and Jarvie, 2007). Early exploitation of gas from these shales was generally limited to formations containing natural fractures, usually with short-lived production, a notable exception being the Ohio Shale Big Sandy Field in Kentucky, USA, which has been on production since the 1920s (Engelder and Lash, 2008). Antrim Shale production followed in the 1930s from the Michigan Basin, but it was the advent of hydraulic fracturing in the late 1940s which aided this development, although not until the mid-1980s did entrepreneurs such as George Mitchell actively target shales as a source of economically producible gas resources. Large-scale hydraulic ‘‘fracks’’ were developed but the sought-after breakthrough occurred when they were used sequentially in horizontal wellbores drilled within the gas-rich shale intervals (King, 2010), leading to the current boom in shale gas and oil production in the USA (Fig. 5). 5. Shale resources – social responses Fig. 2. Definitions of unconventional hydrocarbons based on (a) thermal maturity and (b) organic matter content of the rock, illustrating tight gas in organic poor siltstones and fine-grained sandstones, shale gas from organic-rich shales and coal bed methane from coals (Total Organic Carbon – TOC). Modified from Core Laboratories.

either non-toxic or of very low toxicity and are used to improve the results of the stimulation operation and the subsequent productivity of the well. The hydraulic fracturing process is undertaken over multiple stages in the horizontal well bore through the reservoir section. Each stage or section of the well-bore is physically isolated using moveable seals or plugs, to both target the best reservoir sections and to maximise the effectiveness of the process. In a typical well, the well-bore will be stimulated or ‘‘fracked’’ in 30–40 such stages, depending on the length of the horizontal bore, with successive fracturing of each stage inwards from the end of the well (e.g. King, 2012). Production profiles for shale wells are very different from those of conventional reservoir wells and lack the typical, often lengthy plateau production periods. Instead they have a relatively short-lived high initial production flow rate, often only lasting a few months, followed by a rapid, exponential decline into low rates which can continue for many years (Fig. 4): indeed the oldest shale wells in the US, producing from the Devonian-aged Ohio Shale, are over 90 years old (Engelder and Lash, 2008). However, most wells reach an economic production threshold long before this, with the potential need to ‘‘re-frack’’ the well to maintain enhanced productivity. 4. Shale resources – overview and concepts Shale resources have a long history of exploitation (Selley, 2012), with the first recorded gas production at Fredonia, Pennsylvania, USA, in 1821 where Devonian-aged shale provided gas for street lighting from a simple vertical well (Harper, 2008). Similarly, in the late 19th Century, shale-sourced gas at Heathfield, Sussex, lit the railway station (Selley, 2005). Gas-charged shales were later recognised by early oil-well drillers in the USA as a potential hazard, often resulting in fatal explosions and fires. These shales, generally of Palaeozoic age, were often encountered during

In the UK, shale resources and fracking are supported by Government and industry but public opinion appears against it, particularly following the moratorium imposed by Government in 2011 following the minor fracking-related seismic events during operations on the Preese Hall-1 well (Westaway, 2016). Substantive reports into these events (Royal Society, 2012; Green et al., 2012) concluded that fracking should be allowed under strict control, allowing the Government to lift the moratorium in 2013. However these events have been well-publicised, leading to the rejection of recent shale-gas drilling planning applications on environmental grounds, although this may have been pragmatic to avoid a long, expensive and likely contentious appeal process. Indeed, even Government does not have a consistent view, as the House of Commons in January 2015 rejected the moratorium on fracking proposed by the Parliamentary Environmental Audit Committee whereas a moratorium was approved by the Scottish Parliament. The situation was succinctly summed up by Moses (2015): ‘‘the anti-fracking campaigners hold all the cards. They can make any statements they want without any foundation in fact, but any response will be checked for the slightest mistake or exaggeration’’. Until this imbalance can be rectified, there appears little chance for the reality of the situation to be believed by the general public although as this paper was undergoing revision, approval was given to Third Energy in May 2016 by North Yorkshire County Council for fracking of a well to test the Bowland Shale potential beneath the Kirby Misperton gas field (North Yorks CC, 2016). This was followed by the UK government’s climate change advisory body cautiously endorsing shale gas as consistent with Britain’s carbon reduction targets as long as it displaced imported gas (The Times, 2016). Whether shales will offer a third major energy source to the UK (after coal and North Sea oil) remains conjectural. Only a small proportion of the enormous volume of shale hitherto proposed as reservoirs in the UK (DECC, 2010; Andrews, 2013; Andrews, 2014; Monaghan, 2014) are likely to actually have viable economic potential based on the criteria for effective shale reservoirs discussed below. The most promising reservoir potential lies within relatively small areas of organically rich, thermally mature shales (e.g. EIA, 2015): a thorough, rigorous re-examination of their volumes and hydrocarbon potential would appear timely.

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Fig. 3. Schematic diagram of a horizontal shale-gas well, illustrating the hydraulic fracturing (fracking) technique and associated infrastructure (courtesy Al Granberg/ ProPublica).

6. What makes a shale reservoir? Shales comprise fine-grained rocks defined by a microstructure of <5 mm grain size, with variable lithology and mineralogical composition (Lazer et al., 2015), characterised by nanometer-scale pores (‘‘nanopores’’) with extremely small pore throats and negligible permeability (Scheiber, 2010). These rocks are therefore ‘‘non-reservoir’’ in the conventional sense where they can form the cap rock or seal to a trap, and can only be made producible by the creation of artificial permeability through the fracture-stimulation of horizontal wells. Many, but not all, such reservoirs are organicrich and are generally hydrocarbon source rocks with a variable thermal maturation state, most having charged conventional reservoirs earlier in their burial history. Mineralogy is variable and is critical to a successful shale reservoir, as shale ‘‘frackability’’ (the ability to successfully hydraulically fracture a shale) requires a large proportion of ‘‘brittle’’ minerals such as silica or carbonate forming the detrital matrix and/or diagenetic cements compared to the proportion of ‘‘ductile’’ clay and organic matter components (King, 2012; Imber et al., 2014). Silica-rich shales in North America include the Barnett, Marcellus, Mowry and Duvernay Shale

Formations, while the Eagle Ford and Niobrara Formations and Vaca Muerta Shale Formation (Argentina) are carbonate-rich shales (Fig. 5). The US Haynesville Shale Formation is a mixed siliceous-calcareous shale but, importantly, none of these shales is totally clay-rich, although the Marcellus Shale Formation can locally reach up to 50% clay. While the basic principles of shale oil reservoirs are similar to those for shale gas, the much larger oil molecule size relative to pore throat diameter results in large capillarity effects, which greatly restrict the flow capabilities of shales with respect to oil. Shale oil resources are more economic and therefore more effective when hybrid reservoirs which consist of a coarser grained, morepermeable lithology in which the productive wells can be drilled and completed are intimately associated with the shale source rock. Natural fractures are commonplace in many shale reservoir formations (Ferrell et al., 2014) and are related to local faulting and to development of regional tectonic stress patterns (Imber et al., 2014). These can be either open or cemented by minerals such as calcite and can influence the effectiveness of well stimulation (hydraulic fracturing). The aim of hydraulic fracturing a well is to achieve a large artificial ‘‘flow-unit’’ or stimulated reservoir volume

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Fig. 4. Typical production decline curves for the major US shale-gas reservoirs. Note the high initial production (IP) rates, the rapid variable exponential decline and the long production time, which is potentially greater than 30–40 years.

Fig. 5. Distribution of major US shale resources (U.S. Energy Information Administration, 2013).

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Fig. 6. Marcellus Shale Formation (for location see Fig. 4) SEM image showing organic porosity development and pore schematic diagram illustrating free versus adsorbed gas storage at a molecular-level. The large green ‘‘circle’’ represents the relative size of an oil molecule, illustrating why oil is impossible to produce from shales and require a hybrid reservoir.

by creating a complex artificial fracture network to connect the hydrocarbon-bearing ‘‘nanopores’’ with the wellbore. Small-scale local fracture systems can be exploited and extended from the wellbore into the reservoir by the stimulation, but cemented fractures may be deleterious as the cements generally have a lower fracture threshold than the surrounding shale and much of the stimulation energy is diverted into opening these fractures rather than the stronger shale matrix. Gas storage within organic-rich shales occurs as both free gas within the pores of the rock matrix and any fracture system and, importantly, adsorbed onto organic matter and clay mineral

surfaces, particularly the walls of organic-matter hosted pores (Bernard et al., 2012; Romero-Sarmiento et al., 2013) (Fig. 6), many of these being nanopores which appear to be created during thermal maturation of the shales (Bernard et al., 2012; Mathia et al., 2016). While free gas predominates (Jarvie et al., 2007), the relative importance of adsorbed gas is highly variable (Fig. 7), both within and between shales, and is a complex function of the amount and type of organic matter present, pore size distribution, mineralogy, level of diagenesis or maturation state and reservoir conditions (temperature and pressure) (Bustin et al., 2008). 7. Shale reservoir summary

Fig. 7. Methane adsorption relationship with organic matter content within shale gas reservoirs, showing the strong relationship between absorbed gas and organicmatter hosted porosity. Modified from Core Laboratories.

 Shale reservoirs exhibit high levels of heterogeneity and complexity, with most of the hydrocarbon resource stored in ‘‘nanopores’’ with very low matrix permeability. Reservoir complexity is exacerbated by variable amounts of natural fracturing, which have low porosity and high permeability. Gas storage is related to porosity and to adsorption on both organic matter and clay minerals.  Shale reservoirs comprise a hydrocarbon source rock which is likely to have previously charged ‘‘conventional’’ reservoirs within the basin with oil and gas.  Shale reservoirs contain non-expelled hydrocarbons retained in the source rock, either gas (shale gas) or ‘‘liquids’’ (shale oil), depending on thermal maturity.  Shale-oil reservoirs commonly benefit from migration of oil from organic-rich beds into stratigraphically adjacent more-permeable lithologies, forming ‘‘hybrid’’ reservoirs.  Shale reservoirs have a very low ‘‘natural’’ permeability: they can form the cap-rock or seal to ‘‘conventional’’ reservoir traps, but produce hydrocarbons economically only when permeability is created or enhanced artificially. They must have porosity capable

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of storing the generated hydrocarbons, which are recovered using modern horizontal drilling and multi-stage fracturing technologies.  Productive shale reservoirs have a ‘‘frackable’’ mineralogy – a ‘‘brittle’’ mineral fabric rather than a ‘‘ductile’’ clay-rich composition.

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8. Shale gas Shale gas resources are distinguished by gas ‘‘type’’ (Jarvie et al., 2007), typically with either biogenic or thermogenic gas production (Claypool, 1998) from low porosity and permeability shales forming a self-contained source – reservoir – seal system.

Fig. 8. Bakken Shale Formation stratigraphic column, illustrating the ‘hybrid’ shale oil reservoir concept.

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Fig. 9. Eagle Shale Formation stratigraphic column, illustrating the shale oil reservoir.

Biogenic gas-shales contain gas generated by biogenic degradation of organic matter within the source rocks, are thermally immature due to shallow burial and typically have formation temperatures of 40–80 8C. At temperatures above 80 8C most bacteria are destroyed and thermally generated gas becomes predominant. Biogenic gas-shales include the Antrim Shale Formation in the Michigan Basin (Martini et al., 2003) and the shallow sections of the New Albany Shale Formation in the Illinois

Basin. They are characterised by dry gas adsorbed onto organic matter with, after de-watering, modest initial production (IP) rates of 40–500 thousand cubic feet of gas per day (MCFD) followed by long production of over 30 years. Thermogenic shale gas plays range in thermal maturity from early gas-window such as the New Albany Shale Formation to the very prolific late gas-window plays such as the Barnett, Marcellus and Haynesville Formation Shales. In contrast, thermogenic shale wells have much higher productivity,

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with typical Marcellus Shale wells having IP rates of 10 million cubic feet of gas per day (MMCFD), ranging up to 50 MMCFD (Fig. 4). Estimated ultimate recoveries (EUR) for the Barnett Shale Formation is in excess of 2.5–3.5 billion cubic feet (BCF) per well (Mortis, 2004) and 5–7 BCF per well in the high-maturity Marcellus Shale of northern Pennsylvania. Most shale-gas plays have been affected by tectonic uplift, which effectively shuts off the hydrocarbon generation process by lifting them out of the gas generation ‘‘window’’. Due to the impermeable character of the shales, most of the gas is retained in the rock unless released by fracturing or faulting related to the tectonic activity. This has two benefits: the gas is generally overpressured in uplifted reservoirs and the cost of drilling to reach the shales is reduced due to lesser drilling depths.

9. Shale oil Shale oil is a more recent concept, with large potential in the USA in formations such as the Devonian-Mississippian (Early Carboniferous) Bakken Shale and the Cretaceous Niobrara, Mowry and Eagle Ford Shales. While the basic principles are similar to that of shale gas, the much larger oil molecule size relative to pore throat diameter results in large capillarity effects, which greatly restricts the flow capabilities of these shales with respect to oil. Shale oil resources are more economic but can only be economically produced from what are known as hybrid reservoirs. These comprise coarser grained, more-permeable lithologies intimately associated with the shale source rock into which the horizontal production wells are drilled and completed. In the case of the Bakken Formation, the hybrid reservoir comprises a siliceous carbonate unit which is sealed between the Lower and Upper Bakken Shale source rocks (Fig. 8). Lateral wells are completed within this Middle Member of the Bakken Formation to create a permeable reservoir that can effectively produce the oil generated by the adjacent shales. Thin interbeds of more permeable lithologies, such as siltstones and limestones within the shale source rock, can also enhance shale production capabilities, examples being limestones developed within the Eagle Ford Shale (Fig. 9) and siltstones within the

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Mowry Shale. In these cases, oil production is achieved by drilling and completing lateral wells in sections where the interbedded units are best developed.

10. Exploration and exploitation of shale reservoirs Hydrocarbon-bearing shales represent a complete petroleum system (Magoon and Dow, 1994), comprising the hydrocarbon source, reservoir and seal within a single rock unit (Jarvie et al., 2007). They are generally described as ‘‘statistical plays’’, as each well not only accesses a separate portion of the laterally continuous shale reservoir with its very low inherent permeability and variations in geological parameters, but also due to the variable and, to-date, relatively un-predictable, effectiveness of the fracking process to create an artificially permeable reservoir. Effective production of artificial permeability by the hydraulic fracturing of horizontal reservoir sections, optimally located within the shale, is the key to successful access to such resources. Successful exploration for shale resources, whether for shale oil or shale gas, is dependent on the discovery of good quality organicrich shale of large regional extent and thickness, and suitable thermal maturity. Present-day depth is also critical, with the shale at an economically drillable depth. While this is variable between basins, typically in the USA, shale gas production is optimal at 1000–4000 m depths. Shales at depths of less than 1000 m suffer from low reservoir pressures, the difficulty of generating vertical fractures during hydraulic fracture stimulation and an increased risk of surface or ground-water issues. The inability to initiate and propagate vertical fractures at these shallow depths is largely due to the associated very low overburden pressures which results in the formation of horizontal ‘‘pancake’’ fractures parallel to the wellbore which are not effective at increasing reservoir permeability. This is because horizontal fractures generally fail to connect enough shale volume to the wellbore to drain hydrocarbons from the reservoir. However, this lack of vertical fracture height growth at shallow depths is good from an environmental standpoint as it greatly reduces the risk of groundwater contamination from deeper hydraulic fracturing operations unless a fault is encountered and stimulated. At depths greater than 4000 m shales are

Fig. 10. Shale gas exploration geological parameter summary.

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generally uneconomic due to increased drilling costs. The exception to these rules are prolific highly over-pressured shales such as the Haynesville Shale or Eagle Ford Shale Formations where the much greater gas content allows economic production from greater depths. Other general parameters are given in Fig. 10. Defining areas of potential shale resources is initially based on evaluation and mapping existing outcrop mineralogical and geochemical data such as organic matter type, richness and maturity, augmented by well log, drill cutting or core analyses (Charpentier and Cook, 2011; Wang and Carr, 2012). These parameters are then mapped to high-grade regions of potential interest or ‘‘sweet-spots’’, which can be defined as areas where the shale has good organic content, quality and maturity, good ‘‘frackable’’ characteristics (mineralogy), thickness and depth. Seismic data are increasingly being used in ‘‘sweet-spot’’ definition, based on seismic attribute evaluation (Løseth et al., 2011). High organic matter content within a shale affects its seismic character due its low density and low elastic moduli (Fig. 11). 3-D seismic data are generally used for such shale-quality ‘‘sweet-spot’’ evaluation, but existing good quality 2-D regional seismic data can also be utilised. In general, at shale thicknesses exceeding the seismic tuning effects of the formation boundaries, an organic-rich shale containing gas in particular will have a much lower density than organic-poor or non-gas-bearing shale, which creates a seismic attribute anomaly which can be mapped. Calibration of seismic attributes such P and S-wave anisotropy to well-log and core data allows potentially resource-rich areas of the shale to be determined and mapped, allowing leasing to be optimised and reducing the need for the pilot hole drilling. Seismic data are also critical in optimising the location of wells for the identification of geo-hazards (particularly faults) and areas of better reservoir development, particularly with lateral production wells typically extending 1500–3000 m from the surface location. Drilling across even very minor faults may lead to lost circulation problems or difficulties with geo-steering the horizontal wellbore to keep it in the target zone. Completion across such faults can result in reduced or loss of hydrocarbon production by water influx from a breached cap-rock or creation of seismic (earthquake) activity due to fault-plane lubrication. Multi-well pad drilling where four to eight or more horizontal wells are drilled from a common surface pad is important to minimise surface disturbance and to facilitate collection and transport of produced hydrocarbons. Seismic data is useful in selecting the location of well-pads as they are preferentially in areas of minimal faulting. Vertical pilot wells with detailed wire-line logging and core data collection are generally drilled at spacing intervals of around 5 km or when shale parameters have potentially changed, as indicated by logs from non-cored wells or seismic-attribute variation. Lateral production wells are generally drilled from the pad in opposite directions perpendicular to the direction of maximum horizontal stress, with parallel horizontal well-bores generally being 180–250 m apart. Geological stress is the most important control of fracture azimuth (Fisher and Warpinski, 2012), with induced fractures propagating in the direction of maximum stress and perpendicular to the direction of least principal stress. At depths greater than 1000–1200 m, maximum stress is generally due to overburden, so vertical fracture propagation predominates and the fracture azimuth is controlled by tectonic stress. Fracture orientation can be obtained from wireline logging (including image logs and/or dipole sonic logs) of the reservoir interval within a vertical pilot hole and by micro-seismic monitoring of the fracture stimulation, providing valuable information for determining principal stress directions for drilling the lateral production well. Successful completion (fracking) of the lateral wells is very dependent on the characteristics of the shale penetrated. ‘‘Brittle’’ shales (silica or carbonate-rich) have much better completion

Fig. 11. Shale seismic parameters, illustrating the effects of low density kerogen in organic-rich shales.

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Fig. 12. Surface map of micro-seismic data recording actual rock-breaking events from sequential hydraulic fracture stages on two horizontal wellbores drilled from the same well pad, illustrating the variable fracturing results, potentially due to either or to both geological variations in the shale or to mechanical variations in the stimulation process between stages. Colours represent different frack stages.

potential and hence flow-rates than ductile, organic-matter or clay-rich shales. Placement of the lateral in a brittle zone, preferably located stratigraphically adjacent to an organic-rich layer, offers the best production potential. Horizontal wellbores are completed with 20 or more separate and distinct fracture stimulations, the perforations located generally at regular intervals with exceptions in the cases of existing geo-hazards such as faults. Each of these sets of perforations, or stages, are isolated during the completion process by temporary seals, either packers or plugs, which effectively separate the completion of each stage. Microseismic monitoring of fracture initiation and propagation during individual completion stages (Zoback et al., 2010; Maxwell, 2014; Baig and Urbancic, 2014) often indicates variable results (Fig. 12), with some intervals showing little fracture activity, suggesting that variations in shale parameters along the horizontal wellbore can be significant. Non-completion of such intervals can potentially lead to considerable savings in costs with little effect on overall well productivity. The volume of productive reservoir in a shale well is known as the ‘‘flow-unit’’ and is defined as the portion of the shale which has been accessed by the creation of a fracture permeability network through hydraulic fracturing (Aguilera, 2013). This is generally a 30–100 m diameter volume of rock located along the lateral well bore. Induced

fractures tend to grow outwards and upwards due to both the effects of buoyancy on the water-based frack fluids and to a general decrease in overburden pressure with decreasing depth. In detail the reservoir volume created by completion (fracking) of a well is difficult to determine and is currently under intense investigation, the best determinations being made using micro-seismic measurement of the fracking process combined with 3-D seismic. Currently, completion is largely undertaken using water as the frack medium due the large volumes required for each stage. Minor amounts of chemical additives (typically 0.05% by volume) are used to reduce formation damage such as clay swelling, minimise precipitation of minerals dissolved from the rock (e.g. calcite, iron), and to enhance penetration of the shale fabric (surfactants and friction reducers, as well as biocides, and scale prevention agents). Proppants, typically quartz sand or artificial ceramic material, are used to keep the newly created fractures open and form the other major component of the pumped fracture stimulation, Flow-back of frack fluids typically occurs during initial production from a well; however, the volumes of frack fluid produced are typically less than 20–30% of the injected water, particularly in the case of high thermal maturity shales such as the Marcellus which appear to be very hydrophilic, likely due to the highly dehydrated state of the clay mineral fabric.

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Unless the prospective reservoir section is located within a thick section of non-reservoir shale, ‘‘frack-barriers’’ are necessary to contain the induced fractures and to prevent the accidental extension of fractures into adjacent water-bearing reservoirs. Frack-barriers are most commonly dense limestones, clay-rich shales or other lithologies with very different fracture initiation properties from the reservoir shale, ideally located both above and below the prospective reservoir unit. Lean, organic-poor shales can also form a frack-barrier as they have different fracture properties from the organic-rich reservoir shales. 11. Shale resource determination The total volume of shale resources can be determined by well log interpretation after calibration from core data (Scotchman, 2014). Due to the need to artificially create a permeable reservoir post-drilling and logging, and because the effectiveness of the hydraulic fracturing process cannot easily be determined, historical production data is used to determine the economically recoverable (producible) reserves or ‘‘Estimated Ultimate Recovery’’ (EUR) (Hill and Jarvie, 2007) of each producing well. The EUR for a shale well is largely dependent on the following factors discussed below: – – – –

Shale quality (thickness, richness, reservoir potential) Horizontal well-bore length Number of hydraulic fractures created in the reservoir section Effectiveness of these fractures in accessing the hydrocarbonbearing pores – the stimulated rock volume.

seismic activity and increased disturbance such as noise, dust and vehicular, associated with drilling, completion and production operations. These hazards are commonly associated by the general public with fracture stimulation, however, recent detailed studies have shown that fracture stimulations themselves actually have minimal impact. Despite the most infamous fracking test in the UK, on the Bowland Shale in Cuadrilla’s 2011 Preese Hall #1 well resulting in minor earthquakes due to release of local tectonic stress (Westaway, 2016), there is little hard evidence for the major environmental consequences from the large-scale use of hydraulic fracturing across many areas of the USA and parts of Canada since the early 1990s (e.g. Davies, 2011). With the many thousands of wells now completed by hydraulic fracturing, it is likely that incidences of frack-related seismicity and groundwater contamination may have occurred but these appear to be related to individual well or procedural processes rather than to the completion process in general (Davies et al., 2012). Although more than 35,000 fracture stimulated shale gas wells have been drilled and completed in the USA, only a single possible case of associated induced seismicity has been documented in a study by Hitzman et al. (2013), although low-level seismicity has been associated with fracking in the Horn River Basin of British Columbia, Canada (Baig et al., 2015; Bosman et al., 2016). However, most documented cases of induced seismicity appear to be associated with waste-water injection (e.g. Holtkamp et al., 2015), a practice which is currently under intense scrutiny.

13. Groundwater issues The EUR is calculated from the well initial production rate (IP) in combination with a type decline curve (Fig. 4) and is generally in the range of 15–35% of the calculated gas in place (King, 2010). Clearly, such reserve determinations are dependent on the use of a suitable production decline curve which presents considerable difficulty in areas lacking previous production. To overcome this, increased use is being made of short-term flow tests to aid the determination of the EUR. 12. Environmental considerations Potential hazards arising from shale production include the risk of groundwater contamination with frack fluids, the leakage of hydrocarbons during subsequent production, the risk of induced

In many basins around the world, hydrocarbon leakage to the surface and groundwater contamination is an entirely natural occurrence, with gas being derived from high-maturity coals and shallow reservoirs (Wilson, 2014) or shallow-buried thermally mature shales (Lavoie et al., 2016): indeed this is how early explorers located hydrocarbon-bearing basins in the 19th century. Many thousands of wells have been drilled since then, the earliest with only rudimentary casing, if any, and with little or no sealingoff after abandonment. This, along with any faults or fracture systems cutting un-cased well-bores, may have allowed subsurface leakage of hydrocarbons from reservoir intervals up into shallower levels, with potential for groundwater contamination. This situation has been known for many years in the old production

Fig. 13. Appalachian Basin cross-section showing the relationship between the deep Marcellus Shale Formation reservoir and shallow aquifers.

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Fig. 14. Possible risk scenarios for shallow and deep gas leakage from shale gas wells and their mitigation.

areas of the USA, such as the Appalachian Basin, but has only come to the forefront with the re-activation of the petroleum industry in these areas as the application of hydraulic fracturing for shale gas extraction has allowed the economic recovery of previously inaccessible resources (Osborn et al., 2011). While contamination may have occurred, the association with hydraulic fracturing is generally unproven (Davies, 2011) and studies are being undertaken to attempt an understanding of this highly contentious issue

(Vengosh et al., 2013; Baldassare et al., 2014). One such recent study undertaken prior to drilling of Marcellus Shale gas wells (Molofsky et al., 2011) found that methane gas was present in ground waters prior to the drilling or fracking of any shale gas wells, indicating natural gas migration through natural geological processes was the likely cause. Clearly, contamination of groundwater during any stage of shale exploitation, whether by drilling, completion, production, or abandonment above naturally

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occurring baselines, is unacceptable and much effort is made to minimise and mitigate this risk particularly by installing additional casing across aquifers and proscribing minimum rock thicknesses between aquifers and production intervals. A simple cross-section of the north-east USA Appalachian Basin (Fig. 13) illustrates some of these groundwater issues. Most groundwater wells tap shallow sands, gravel and aquifers at depths of around 100 metres. Beneath this, between depths of around 150 and 600 metres, lies an interval of generally isolated sands from which early hydrocarbon production took place and now is a potential hazard to drilling. In this area the Marcellus Shale Formation occurs much deeper in the basin at depths of 1100– 2100 m, the overpressured nature of the reservoir indicates sealing from shallower layers by regional seals within the overlying sediments. This thickness of overburden is more than sufficient to prevent vertical connection between a completed well and nearsurface aquifers, as illustrated for the major shale plays in the USA (Fisher and Warpinski, 2012), the largest frack on record attaining a height of 588 m but with a chance of the frack-height exceeding 350 m of around 1% (Davies et al., 2012). Circumstances can be envisaged where this overburden seal may be compromised and Fig. 14a and b illustrate potential scenarios by which natural gas could leak into shallow aquifers during drilling, completion and production. Gas can leak from reservoirs, both shallow or deep, penetrated by the well bore that are not effectively isolated and sealed from the shallow aquifers by proper casing and cementing of the well bore. Leakage from deeper gas-bearing intervals via faults cut by the well bore into shallow aquifers can also be envisaged, again due to poor casing or cement integrity. These risks can be mitigated by proper drilling procedures with the use of drilling mud of adequate weight and composition and with the subsequent setting of additional surface casing deeper to below any potential aquifer or fault zones, sealed by full cementing. Bad or incomplete cementing of the casing are the most likely causes of well-related gas leakage, along with the failure of abandoned well casing and capping integrity (Davies et al., 2014). Completion of well-bore sections containing large faults or through-going natural fracture systems that extend above or below the reservoir interval is a further potential risk and should be avoided. However, it should be noted that many reservoirs, such as the Niobrara Formation in the USA, can only be successfully completed due the many natural fractures and faults cut by the horizontal well bores that are restricted to the brittle reservoir zone. At best, fracking such intervals is a waste of energy, fluids

and proppant, while the risks are much greater as faults can be re-activated as conduits to overlying water-bearing sections which can flow into the well, resulting in loss of the well due to water rather than hydrocarbon production, with the potential risk of contamination of the water-bearing section with drilling and completion fluids and, potentially, gas. 14. Induced seismicity As discussed above, major faults and fractures zones should be avoided in production well-bores, either vertical or horizontal, as completing across such zones greatly increases the risk of well failure, contamination by leakage of frack fluids or hydrocarbons and, additionally, the risk of low-level seismic activity. As discussed above, the disposal of fluids into the sub-surface unrelated to fracking has been implicated in several cases of seismic activity in the USA (Davies et al., 2013) This seismic activity is believed to be due to the lubrication of fault zones by the injected fluids, releasing inherent tectonic stresses as minor earthquakes. While this may actually be beneficial in areas of high tectonic stress build-up by releasing stress as low level events rather than as a large, potentially damaging earthquake, any such seismic activity related to fracking is obviously of concern. These risks can be mitigated by the acquisition of a geo-hazard 3-D seismic survey over the lateral well track to identify any faults or fracture zones, with more detailed logging of the lateral well-bore than just the gamma-ray log used for geo-steering to locate any minor subseismic resolution faults and fractures. The failure to perform such basic risk reduction can be the unintentional lubrication of an unrecognised fault zone, such as occurred during completion of a vertical reservoir section of the Preese Hall #1 well in Lancashire, UK, in 2011. This resulted in minor earthquakes as a result of local tectonic stress release (Royal Society, 2012; Green et al., 2012; Westaway, 2016), the public outcry leading to a Governmentimposed moratorium on shale drilling while investigations were carried out, setting back the development of shale resources in the UK by at least 5 years. 15. Completion or ‘‘frack’’ fluids The hydraulic fracturing process, as the name suggests, uses fluids pumped at high pressure in large volumes into the well-bore to initiate and propagate fractures in the shales. As noted earlier, these fluids are predominantly composed of water and sand or

Table 1 Typical additives to hydraulic fracturing fluid comprising 0.05% of total volume. Water and quartz sand (proppant) form 99.95% (Chesapeake Energy, 2009; South Western Energy, 2014). Component

Main compound

Purpose

Common use

Acid Biocide Breaker Corrosion inhibitor Cross-linker

Hydrochloric or muriatic acid Glutaraldehyde Sodium chloride n,n-dimethyl formamide Borate salts

Swimming pool cleaner Disinfectant; medical and dental equipment steriliser Table salt Pharmaceuticals, acrylic fibres and plastics Laundry detergents, hand soaps and cosmetics

Friction reducer Gelling Agent Iron control

Petroleum distillate Guar gum or hydroxyethyl cellulose Citric acid

Dissolves minerals and initiates rock fractures Eliminates bacteria in the water Delays breakdown of gel polymer chains Prevents pipework corrosion Maintains fluid viscosity as temperature increases ‘‘Slicks’’ the water to minimise friction Thickens the water to suspend the proppant Prevents precipitation of metal oxides

Clay Stabiliser

Potassium chloride

Oxygen scavenger

Ammonium bisulphite

pH adjusting agent

Sodium or potassium carbonate

Scale inhibitor Surfactant

Ethylene glycol Isopropanol

Stabilises swelling clay minerals and creates a brine carrier fluid Oxygen removal from the water to reduce pipework corrosion Maintains effectiveness of components, e.g. cross-linkers Prevents scale formation Increases fracture fluid viscosity

Cosmetics, hair, make-up, nail and skin products Thickener used in cosmetics, food stuffs Food additive; food and beverages; lemon juice c. 7% citric acid Used in low-sodium table salt substitute, medicines and IV fluids Cosmetics, food and beverage processing, water treatment Laundry detergents, soap, water softener and dish washers Household cleansers, de-icer, paints and caulk Glass cleaner, multi-surface cleansers, anti-perspirant, deodorant, hair colour

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other proppant (99.95%), with minor amounts of other chemicals such as surfactants to reduce surface tension and capillarity effects, corrosion inhibitors and biocides (see Table 1). Minor amounts of petroleum distillate (light oil) may also be added to reduce fluid friction (so-called ‘slick water’). After completion of a well, the initial production phase is a clean-up period during which frackfluid generally flows back to the surface before any hydrocarbon production. The volume of returned frack-fluid can be up to some 70–80% of the amount injected and this is generally cleaned for reuse or treated to remove any remaining chemical traces before disposal. Water usage by hydraulic fracturing is high, typically 8–23 million litres per well with 21 million litres for a typical Marcellus Shale well, dependent on the number of frack stages. This certainly a critical issue, particularly in areas of restricted supply where it could be in competition with drinking water and irrigation supplies. Recycling and re-use of frack-water is therefore essential, and the use of cleaned-up and recycled water from secondary sources such as from desalination may be required. This is potentially a critical issue in arid areas due to potential competition for scarce water resources from fracking: indeed in the Karoo region of South Africa this fear has led to fierce public opposition and a Government moratorium on shale exploration lasting several years. 16. Shale resources – USA versus Europe and the rest of the world Until the late 2000s, shale resources were predominantly a US phenomenon, with estimates of potential shale gas resources of 2540 trillion cubic feet (TCF) (EIA, 2013). Development of these potentially vast resources has been facilitated by a buoyant exploration and drilling industry, a well-developed production and

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pipeline infrastructure and a private leasing and mineral rights ownership virtually unique in the world. The combination of these factors has led to a boom in shale drilling and production, with the result that the USA is likely to become a net gas-exporter and has the potential to become self-sufficient in oil production. The lack of the combination of these factors elsewhere in the rest of the world probably explains the slow and limited development of shalebased resources. Worldwide, potential shale gas resources have been identified in many countries (Fig. 15) with estimated natural gas resources of some 7300 TCF and shale oil resources of 345 billion barrels (Bbo) (EIA, 2013). In the UK, an initial overview of potential shale gas resources gave an estimate of 5.2TCF (DECC, 2010); subsequent more detailed evaluations of the Carboniferous Bowland Shale in the north of England, the Weald Basin of southern England and the Midland Valley Basin of Scotland have given much larger resource ranges, respectively, of 164–447 TCF gas (Andrews, 2013), 2.2–8.6 Bbo oil (Andrews, 2014) and 49.4–134.6 TCF gas and 3.2–11.2 Bbo oil (Monaghan, 2014). However, a recent risked evaluation of the UK’s technically recoverable shale resources gives an estimate of 26 TCF gas and 0.7 Bbo oil (EIA, 2015). This is contrasted by the recent media speculation surrounding the so-called ‘‘Gatwick Gusher’’ in the Weald Basin, with quoted shale oil resources of over 158 MMbo per square mile, typifing the challenges associated with evaluating, accurately predicting and developing shale oil resources (Whaley, 2015). Elsewhere, shale exploration and production is taking place in countries such as Poland, Canada, China, Argentina and Australia with variable success, but environmental concerns have resulted in drilling bans and moratoria on shale exploration in South Africa (Karoo Basin), France, Germany and Bulgaria to name a few, with strong opposition in other countries such as the UK and Romania. Coupled with these over-riding environmental concerns, other

Fig. 15. Map showing potential for world-wide development of shale gas. Source: United States basins from U.S, Energy Information Administration and United States Geological Survey; other basins from Advanced Resources International, Inc., based on data from various published studies: EIA, 2013.

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than Canada and potentially Argentina, most countries do not have a thriving, low-cost drilling industry or available infrastructure which greatly increases the cost of the intensive drilling and production facilities required for shale resource development. High energy prices, as prior to mid-2014, would be required to offset the higher drilling and production costs, if the environmental concerns can be overcome, allowing potential resources in many areas to be exploited. 17. Conclusions The almost overlooked development of shales as gas reservoirs in the 1980–1990s exploded into the phenomenon of shale gas and later shale oil, firstly in the USA and, later, expanding to the rest of world. By 2014 this had resulted in the USA being able to meet demand from domestic production, challenging conventional hydrocarbon producers such as Saudi Arabia and, arguably fostering the dramatic fall in global oil prices starting in late 2014 continuing today (2016). Shale resources comprising both gas and oil reside in rocks which in conventional petroleum systems form source rocks and cap rocks/seals and show a strong relationship with the organicmatter content of these shales. Exploration and exploitation techniques are very different from those developed over the last 150 years for conventional resources and require a new ‘‘mindset’’. In particular, the production of these resources is entirely dependent on the creation of an artificial reservoir by hydraulic fracturing, with the inherent over-hyped and often erroneous environmental concerns voiced over the process. While concerns over potential climate change due to the extraction of energy from shales are legitimate and timely, these resources have a valuable place in supplying a less carbon-rich energy source than coal while the energy-hungry human race develops economic replacements with climate-neutral alternative energy sources. Acknowledgements The geological concepts for shale gas and oil exploration and exploitation presented in this paper were developed over a fiveyear period working in Statoil ASA’s Unconventional Hydrocarbons team in both Oslo and Houston: I would like to acknowledge the input, shared learnings and suggestions from my many colleagues. I also wish to thank the reviewers, Richard Bottjer, Howard Armstrong and Rob Westaway for their thoughtful and helpful comments and to John Kipps for draughting the figures. Finally, my thanks to PGA Editor in Chief James Rose for his perseverance with the long gestation and revision of this paper. References Aguilera, R., 2013. Flow units: from conventional to tight gas to shale gas to tight oil to shale oil reservoirs. Society of Petroleum Engineers Paper 165360.In: Presented at SPE Meeting, Monterey, CA, USA, 19–25 April. Andrews, I.J., 2013. The Carboniferous Bowland Shale Gas Study: Geology and Resource Estimation. British Geological Survey for Department of Energy and Climate Change, London, UK. Andrews, I.J., 2014. The Jurassic Shales of the Weald Basin: Geology and Shale Oil and Shale Gas Resource Estimation. British Geological Survey for Department of Energy, Climate Change, London, UK. Baig, A.M., Urbancic, T., 2014. Hydraulic fracturing-induced seismicity: an overview of recent observations and implications on development. First Break 32 (7), 61–66. Baig, A.M., Viegas, G., Urbancic, T., von Lunen, E., Hendrick, J., 2015. To frac or not to frac: assessing potential damage as related to hydraulic fracture induced seismicity. First Break 33, 67–71. Baldassare, F.J., McCaffrey, M.A., Harper, J.A., 2014. A geochemical context for stray gas investigations in the northern Appalachian Basin: implications of analyses of natural gases from Neogene-through Devonian-age strata. American Association of Petroleum Geologists Bulletin 98, 341–372. Bernard, S., Wirth, R., Schreiber, A., Schulz, H.-M., Horsfield, B., 2012. Formation of nanoporous residues during maturation of the Barnett Shale (Fort Worth Basin). International Journal of Coal Geology 103, 3–11.

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Please cite this article in press as: Scotchman, I.C., Shale gas and fracking: exploration for unconventional hydrocarbons. Proc. Geol. Assoc. (2016), http://dx.doi.org/10.1016/j.pgeola.2016.09.001