petroleum engineering

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Journal of Petroleum Science and Engineering

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Review of gas adsorption in shales for enhanced methane recovery and CO2 storage

Sneha Rania,∗, Eswaran Padmanabhana, Basanta K. Prustyb

a Institute of Hydrocarbon Recovery, Universiti Teknologi Petronas, Perak 32610, Malaysia b Department of Mining Engineering, Indian Institute of Technology, Kharagpur 721302, India

A R T I C L E I N F O

Keywords: Shale Adsorption Storage Recovery

A B S T R A C T

The concept of increased methane recovery with simultaneous CO2 sequestration in unconventional reservoirs like gas shales has been studied extensively. A clear understanding of storage mechanism and geo-chemical characteristics of shale gas reservoirs is necessary for predicting the gas reserve and evaluating reservoir po- tential. The present article reviews literature on adsorption of methane and carbon dioxide on shale for the purpose of methane recovery with simultaneous CO2 sequestration in shale gas reservoirs. The objective of this article is to discuss the technical aspects related to gas adsorption and characterization (both composition and pore) concerning shale gas reservoirs. The various adsorption mechanisms, different adsorption isotherm types and shales as a microporous adsorbent are discussed. Using the published information in literature, methane and carbon dioxide adsorption in shales and its relationship with different geochemical parameters like organic matter content, mineralogy, pore-structure and moisture as essential controls for gas adsorption in shale are discussed. Studies that answer the concerns on effect of shale composition and pore characteristics on adsorption capacity of heterogeneous shale are also summarised.

1. Introduction

Currently, global warming is a major challenge/concern faced by the scientific community across the globe. Geologic storage of CO2 is being regarded as a promising technique of mitigating global warming (Pachauri and Reisinger, 2007). Shale formations can be probable op- tion of storing CO2 in productive shale gas reservoirs (NETL, 2012). Sequestration of CO2 in gas shale formations holds an additional ad- vantage of enhanced methane recovery/production which can help offset the cost of storage making it an economically viable alternative. Godec et al. (2014) suggested the potential of enhanced gas recovery (EGR) and storage of CO2 in gas shales globally. The economic estimate is predicted to be 71 Tcm of enhanced methane recovery which could facilitate 280 Gt of CO2 storage.

Gas shales are identified as unconventional reservoirs containing natural gas with large amounts reported in US and Canada (Montgomery et al., 2005; Jarvie et al., 2007; Chalmers and Bustin, 2008; Ross and Bustin, 2008). Barnett, Caney, Woodford, Fayetteville, Antrim, Ohio, New Albany and Lewis are some of the potential shale gas reservoirs in the US where natural gas has been exploited. These fine grained shales that produces hydrocarbon varies in wider range from mudstone, siliceous or carbonate to sandstone (Jarvie et al., 2007;

Montgomery et al., 2005; Curtis, 2002; Martini et al., 1996). Tight gas sands, coal and shale are some of the low permeability formations which are termed as unconventional gas reservoirs. Shale gas reservoirs are called unconventional systems as a result of smaller grain size, hydrocarbon being stored in adsorbed state and acting as source which results in formation of pore structure different from conventional sys- tems (Wang and Reed, 2009; Ambrose et al., 2010; Sondergeld et al., 2010). The difference in geological framework separates unconven- tional hydrocarbon systems (such as shale gas) from the conventional hydrocarbon systems (Hill et al., 2007). A conventional hydrocarbon reservoir comprises of source rock, reservoir rock, seal, overburden, thermal maturity, migration, and formation of trap (Magoon and Dow, 1994). On the other hand, shale gas reservoir systems consist of source rock, trap and reservoir, in which shale acts as all three (Martini et al., 1998; Hill et al., 2007; Bernard et al., 2010; Glorioso and Rattia, 2012).

Shale gas is mainly a combination of majority of methane (> 94%), lesser amounts of higher hydrocarbons (ethane, propane and butane), traces of CO2 and N2 found in shale rock (Kalkreuth et al., 2008). The term “gas shale” is known as a fine-grained sedimentary rock which can store natural gas in the porosity system by adsorption (Law and Curtis, 2002; Bustin, 2005; Bustin et al., 2008). The origin (thermogenic/bio- genic) and geochemical type (wet gas/dry gas) control the chemical

https://doi.org/10.1016/j.petrol.2018.12.081 Received 7 September 2018; Received in revised form 3 December 2018; Accepted 29 December 2018

∗ Corresponding author. E-mail address: [email protected] (S. Rani).

Journal of Petroleum Science and Engineering 175 (2019) 634–643

Available online 31 December 2018 0920-4105/ © 2019 Elsevier B.V. All rights reserved.

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composition of shale gas mixture (Jarvie et al., 2007). The gas in shale gas reservoirs is stored in adsorbed form, free form and dissolved form within the pore structure of shales (Curtis, 2002; Ross and Bustin, 2008; Bernard et al., 2010). Free gas is the phase in which adsorbate mole- cules are in random motion and continuously collide with each other. The gas molecules fill the inter-grain pores and fractures. In adsorbed phase, gas molecules remain attached to the surface of solid due to weak intermolecular attractive forces (Gregg and Sing, 1982). The gas molecules form condensed layers at the internal structure of pores (i.e. at solid and gas interface) (Amann-Hildenbrand et al., 2012). The gas molecules (having lower molecular weight) in dissolved phase remain dissolved in the reservoir fluid and on reducing temperature and pressure the gas is released.

Adsorption plays a critical role in storage of gas in shale reservoirs. Since nearly 40–50% of the total gas in a gas shale reservoir is stored by the adsorption mechanism, it is important to understand the me- chanism of adsorption of gases particularly methane on shale rock. The storage and flow properties of gas shale formation are mainly controlled by the geo-chemical characteristics of the formation. The adsorptive capacity of shale is linked to the composition and pore structure of the formation (Ross and Bustin, 2009). Most of the adsorption of methane or CO2 occurs in micropores/nanopores of the organic matter. The clay minerals hold small amount (10%) of the total adsorbed gas and thus also contribute to the gas content of shale (Ross and Bustin, 2007). Ross and Bustin (2009) have shown the dependence of adsorbed capacity with the organic and inorganic composition for Canadian shales. So it may be of interest to explore such dependence for the shale formations. Therefore, studying the organic matter, mineral composition and pore- structure is very important for the characterization of shale rock. The aim of this article is to review the technical aspects of gas adsorption and characterization (both composition and pore) concerning shale gas reservoirs. The current study reviews important literature on adsorption of methane and carbon dioxide on shale for the purpose of methane recovery with simultaneous CO2 sequestration in shale gas reservoirs. Accordingly, various adsorption mechanisms, different geochemical parameters like organic matter content, mineralogy, pore-structure and moisture and their effect on gas adsorption on shale are discussed.

2. Gas storage in shale

2.1. Adsorption mechanisms

Storage of gas (methane or CO2) in shale formations takes place by the mechanism of physisorption (physical adsorption) (Kang et al., 2011). Sorption is a term that includes surface adsorption, absorption and capillary condensation (Gregg and Sing, 1982). Adsorption is the process of accumulation of gas molecules on the surface of a solid by the mechanism of pore volume filling or monolayer formation, thereby forming a high-density in adsorbed phase different from the free gas present in the surrounding (Ross and Bustin, 2009). Adsorption me- chanism has the ability to increase the storage potential of total amount of gas stored, by twice or more than in absence of adsorption (Tinni et al., 2017). In contrast, absorption is defined as penetration of gas or liquid molecules into a solid. The solid on which gas molecules accu- mulate is known as adsorbent and gas molecules are called as ad- sorbate. This occurs due to weak Vander Waal's forces of attraction existing between adsorbate and adsorbent commonly known as physi- sorption and is always reversible (Brunauer et al., 1940). In physi- sorption, van der waals forces are accompanied by electrostatic forces that has the ability to hold more than one monomolecular layers. Physisorption is an exothermic process and heat of adsorption ranges from 8 to 40 kJ/mol (Choi et al., 2001). It forms monolayer at lower pressure and multilayer at higher pressures depending on the ad- sorbate-adsorbent type.

2.2. Adsorption isotherm

Adsorption of gas/liquid on a solid is determined using adsorption isotherm (AI) in which adsorption capacity is measured at varying pressure and constant temperature. Adsorption isotherms are con- structed using gravimetric, volumetric/manometric and chromato- graphic techniques (Ruppel et al., 1972; Lu et al., 1995; Humayun and Tomasko, 2000; Salame and Bandosz, 2001). The similarity between these methods lies in accurate estimation of volume of adsorbent (solid). Volumetric method requires volume of adsorbent to estimate free gas empty space available in sample cell. On the other hand, in gravimetric method, volume of adsorbent is needed for making cor- rection in the buoyancy. Volumetric method involves determination of amount of gas adsorbed by measuring volume/pressure readings and in manometric method pressure values are recorded. Gravimetric method involves constructing adsorption isotherm by measurement of change in weight as noted by microbalance. The chromatographic technique includes determining adsorption isotherm from the breakthrough curves obtained by frontal analysis (Ozdemir, 2004). The volumetric, manometric and gravimetric methods have been reviewed extensively in literature and hence has not been dealt in this paper (Busch and Gensterblum, 2011).

Information regarding mechanism of adsorption, and the porosity as well as the surface area of adsorbent can be obtained from the shape of adsorption isotherm. The IUPAC (International Union of Pure and Applied Chemistry) classifies adsorption isotherms into six types i.e. Type I to Type VI, based on the shape of the curve (IUPAC, 1972). Type I isotherm takes place on nonporous or microporous solid where ad- sorption takes place in a monolayer. In case of Type I isotherm, gas adsorption increases progressively at low pressure (Henry's law region) and the curve is linear at lower pressure and forms plateau at higher pressure (Brunauer et al., 1940). A type I isotherm is usually expressed by Langmuir equation. On the other hand, type II isotherm is observed for nonporous or macroporous adsorbents. In Type II isotherm, an in- flection point exists which signifies the completion of monolayer and beginning of multilayer formation. Type III adsorption isotherm is also observed for non-porous or macroporous adsorbents. This isotherm suggests weak adsorbent-adsorbate interactions. Type IV isotherms are observed for mesoporous adsorbents. Types II and Type IV isotherms are similar except for the hysteresis observed for the later. The hys- teresis loop in Type IV isotherm is because of capillary condensation. Type V exhibits similar properties as that of Type III isotherm except for the hysteresis loop. Type VI isotherms are unusual and appear to be in the form of steps and are theoretical in nature (Gregg and Sing, 1982).

The adsorption isotherm provides information about the maximum amount of gas that can adsorb on a fully saturated porous shale surface as a function of pressure at constant temperature. Adsorption capacity, as indicated from adsorption isotherm can be used to determine the maximum possible gas in place of a fully saturated shale bed. Adsorption of methane on shales is studied by conducting laboratory experiments and developing adsorption isotherms. Various adsorption isotherm equations have been developed to fit the experimental ad- sorption data. Some of the most widely used adsorption isotherm models are: a) Langmuir model, b) BET (Brunauer-Emmett-Teller) model, and c) Dubinin-Polanyi models. Although these equations have been developed for different adsorbent-adsorbate systems, they have been found to work accurately for coal and shale gas system also. The background of the different adsorption isotherm models (Langmuir model, BET Model, Dubinin-Astakhov (D-A) model, Dubinin- Radushkevich (D-R) model and Ono-Kondo model) have been discussed extensively by previous researchers and hence is not included in the present manuscript (Clarkson et al., 1997; Giles et al., 1974; Predescu et al., 1996; Langmuir, 1918; Brunauer et al., 1938; Lowell and Shields, 1984; Dubinin, 1975; Amankwah and Schwarz, 1995; Zhang et al., 2011, 2015; Bi et al., 2016).

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2.3. Shale – as a microporous adsorbent

Shale is a fine-grained clastic sedimentary rock with most of the particle size being less than 62 μm and comprises of varying amounts of organic matter content and complex mineralogy (Alpin and MacQuaker, 2010; Craig, 2004; Gamero Diaz et al., 2013). Unlike coal, adsorbed gas in shales is mostly present in the micropores of the organic matter and a small amount is also present within the clay minerals. In shale gas reservoirs, adsorption is the critical mechanism for gas storage CO2 is potentially stored for the purpose of CO2 sequestration. Under- standing the factors controlling CO2 and CH4 adsorption in shales is essential for modeling both CO2 sequestration and shale gas production. The adsorptive capacity of shale is linked to the composition and pore structure of the formation (Ross and Bustin, 2009). Most of the ad- sorption of methane occurs in micropores/nanopores of the organic matter. The clay minerals also hold small amount (10%) of the total adsorbed gas and thus also contribute to the gas content of shale (Ross and Bustin, 2007). Ross and Bustin (2009) have shown the dependence of adsorbed capacity with organic and inorganic composition for Ca- nadian shales.

2.4. Types of shale

Shale are of various types with respect to its deposition environ- ment. The most commonly available shales in earth are black shales which act as source rock for majority of oil and gas reservoirs. These rocks obtain their black colour from fine particles of organic matter deposited along with mud forming black shales. With increasing depth in the subsurface temperature rises, warming the buried mud that transforms organic material into oil and natural gas deposits. The black colour in rock signifies sediment (from which it was formed) present in an oxygen poor environment. Shales containing calcium fractions or clay minerals are grey in colour. Red shale is due to the presence of hematite while yellow/brown coloured shale is as a result of shale containing goethite (Tomlinson, 1916). The shales can further be di- vided based on the organic matter content into light (poor organic matter content) and dark (rich in organic matter) fractions (Hosterman and Whitlow, 1981). The Barnett, Marcellus, Haynesville and Fayette- ville shales in United States are some of the examples of dark (grey) shales (Blatt et al., 1996).

2.5. Geological controls of shale gas systems

Gas is produced from the organic matter present in shales by thermal (termed as thermogenic gas) and biological (known as biogenic gas) processes. The thermogenic gas is linked to mature shales (organic matter with 1.0–1.1% Ro) which is exposed to higher temperature and pressure (Martini et al., 1998). In biological process, the anaerobic bacteria decompose organic matter to release methane. The biogenic gas is emitted at low temperature (< 70 °C) by microbes and bacteria that are found in fresh water recharge sites (Schoell, 1983; Rice and Claypool, 1981).

In most cases, the gas generated migrates into the porous formations nearby and accumulate as hydrocarbon pools. However, some of the gas remains trapped within the formation itself. Gas shale is composed of organic matter (kerogen), and inorganic clay-/non-clay-minerals. Adsorption properties of gas on fine-grained shales are controlled by different geo-physical-chemical parameters. Apparently TOC content, thermal maturity, mineral matter, and porosity are some of the im- portant controlling parameters that play a key role in adsorption of gas on shales.

2.5.1. Organic matter content Organic matter is an essential parameter which is useful in de-

termining the hydrocarbon that will be generated from petroleum re- servoir. Commonly, organic matter content of a petroleum reservoir is

denoted by the total organic carbon (TOC) content. The TOC content i.e. measured signifies the organic carbon transformed to hydrocarbon, and organic carbon unable to generate hydrocarbon (Jarvie et al., 2007). TOC content, kerogen type, thermal maturation and reservoir volume are some of the parameters used to determine hydrocarbon generation potential of a shale gas reservoir (Ahmad, 2014). The gas adsorption capacity of organically rich shales at a particular pressure and temperature depends primarily on organic matter content but may also be controlled by other parameters such as: organic matter type and thermal maturity, clay content, moisture, pore structure and pore vo- lume (Hao et al., 2013). Previous studies have divided TOC content present in a source rock into three types based on the presence of hy- drocarbons. The first type is organic carbon reserved in the hydro- carbons, second is organic carbon that can produce hydrocarbons and third type is residual organic carbon which is unable to generate hy- drocarbons (Jarvie, 1991; Cooles et al., 1986; Jarvie et al., 2007).

The TOC content varies considerably in wide range among shale reservoirs as well as within a formation itself. This was observed for shales from Lower Cretaceous Fort St John Group of Northeastern British Columbia, which had TOC content ranging from 0.6% to 10.1% (Chalmers and Bustin, 2007). Shales containing organic matter have several advantages that are: low density, high porosity, delivers source gas, imparts anisotropy, varying wettability and enables adsorption (Zhang et al., 2012). Previous studies suggest that methane adsorption capacity in shales is directly related to the TOC content of shale (Cui et al., 2009). However, literature also suggests that shales with poor- organic content have lower adsorptive capacity (Bustin et al., 2008). Besides, a few studies reported no correlation between methane ad- sorption capacity and TOC content for shale (Gasparik et al., 2012). This phenomenon has also been reported for high-rank coals having higher gas adsorption capacities (Laxminarayana and Crosdale, 1999).

Shales consist of dispersed organic matter that is divided into bi- tumen and kerogen. Kerogen is formed by the decomposition of organic matter (remains of plants and some water-borne microorganisms) trapped in sediments and is an essential constituent in hydrocarbon generation. The kerogen is mainly composed of carbon, hydrogen, oxygen, nitrogen and smaller amounts of sulphur. The kerogen type depends on the nature of the organic matter and deposition surrounding (Boyer et al., 2006; Glorioso and Rattia, 2012; Seewald, 2003; Vandenbroucke and Largeau, 2007). The amount of hydrogen present in kerogen is an important parameter in determining the amount of gas formation (Hunt, 1996). Kerogen is divided into three types, based on its composition and type of hydrocarbon it can generate (Tissot and Welte, 1984).

• Type I kerogen: This type is generated mostly from the lacustrine environments and sometimes also from marine environments. It is derived from algal and planktonic material or by decomposition of organic matter during deposition. This type of kerogen is rich in hydrogen and poor in oxygen content. The Type I kerogen is mainly associated with oil production, but also has the ability to produce gas depending on thermal maturity.

• Type II kerogen: It is generated from deep marine settings in redu- cing environments and is formed from the remains of planktons. This type of kerogen is rich in hydrogen and low in carbon content. This type of kerogen can produce both oil and gas with continuous heating and maturation. Sulphur is present in type II kerogen in the form of pyrite, or free sulphur, or it may be bound to the organic structure of kerogen.

• Type III kerogen: This type of kerogen is generated in shallow to deep marine or non-marine environments and is formed from ter- restrial plant debris. Type III kerogen has lesser hydrogen content and higher oxygen content compared to those of Type I or Type II kerogens. The Type III kerogen generally produces gas.

Other than TOC content and kerogen type, thermal maturity is an

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important parameter that plays a significant role in gas adsorption ca- pacity of shales. During kerogen analysis of source rock, three levels of kerogen transformation is noticed that are: immature stage (diagen- esis), mature stage (metagenesis) and post-mature stage (catagenesis). During the immature stage, kerogen is stable and does not transform. In the mature stage, kerogen generates oil and gas and lastly in over- mature stage oil cracking occurs (Peters and Cassa, 1994). Oil and gas are gradually generated from kerogen with mature organic matter, in which oil is the initial hydrocarbon to be released. As the over-mature stage is reached, majority of oil cracking takes place where gas is the main product (Oehler, 1983). Eventually, gas and over-mature organic matter remains trapped in shale gas reservoirs in place of oil.

2.5.2. Shale mineralogy Rock mineralogy and texture can be a critical component in esti-

mating resource potential of shales (Sliwinski et al., 2010). An average shale comprises of 59% clay minerals (illite, smectite, kaolinite) and rest approximately 40% non-clay minerals (such as quartz, chert and feldspar) (Yaalon, 1962). Clay mineral in shales contain crystal layer and pore spaces that provides vacant site for adsorption and surface area greater than rest of the minerals (Aringhieri, 2004; Cheng and Huang, 2004; Wang et al., 2004). However, presence of water in the sorption sites tend to lower the adsorption capacity by swelling clay mineral, filling up sorption sites and restricting pore spaces (Krooss et al., 2002). The mineral constituents in shale are present in the form of siliciclastic and/or carbonate debris and are mostly affected by di- agenesis (Tan, 2014). Shales contain clay and non-clay minerals in varying amounts depending on rock type and climate (Abdullayev and Muslimova, 2010). X-ray diffraction (XRD) and pulsed neutron spec- troscopy techniques used for semi-quantitative mineralogy estimation on Marcellus shale showed 40–80% quartz fractions and 20–60% of clay fraction. However, for Haynesville shale, the quartz fractions varied from 30 to 60% and clay fractions were in the range of 40–70%. Bossier shale showed higher clay fractions than that of Haynesville shale (Passey et al., 2010; Hammes et al., 2011). The structure of clay minerals has two blocks, in which the first one has tetrahedral silicate sheet with oxygen ions at the corner and second block is octahedral in shape linked with hydroxyl/aluminium ions at the corner (Grim, 1968).

The clay minerals in shales contain fine pores mostly micropores and considerable surface area which contribute to the internal structure needed for methane adsorption (Valzone et al., 2002; Venaruzzo et al., 2002). The shales with high clay content have higher porosity and permeability in comparison to shales with higher silica content (Pathi, 2008). In some cases, shales rich in clay are reported to have lower adsorptive capacity. This tendency is mostly observed for moisture- equilibrated shales in which clays are saturated with water. Shale samples with 60–90% quartz and calcite will have lower internal sur- face area and thereby lower gas adsorption capacity (Ross and Bustin, 2007). Contrary to this, detrital quartz possesses high porosity and permeability (Bustin et al., 2008). Siliceous/quartz-rich shales exhibit absence of micro- and meso-pores (Ross and Bustin, 2009). It has also been reported that shales with low carbonate content have less por- osity. Previous studies show considerable amount methane sorption in clays and clay-rich shales (Lu et al., 1995; Ross and Bustin, 2009; Gasparik et al., 2012).

Other than adsorption, mineralogy largely controls the gas pro- duction of shale gas reservoir. Higher production shale gas wells have higher quartz content (> 40%) and low clay mineral content (< 40%) (Britt and Schoeffler, 2009). Brittleness and fracability of shale in- creases with higher quartz and carbonate contents. Shales with higher clay mineral content have lower fracability (Binnion, 2012). The di- agenetic transformation of minerals affects the physical properties of shales and this impacts fracability (Zargari et al., 2013). Generally, depending on the origin and diagenesis of shale formation, illite may be present as dominant clay mineral. Illite is alumino-silicate clay sized mineral and the structure includes repetitive TOT (tetrahedron-

octahedron-tetrahedron layers). Basically, derived from weathering of detrital illite and the two types of structural illite are denoted as 1 M and 2 M. The chemical composition of illite is (K,H3O)Al2Si3AlO10(OH)2. With rise in temperature, illite results in an end product which is muscovite. Glauconite is a specific type of illite rich in iron found in marine environment and formed as a result of slow sedimentation. Kaolinite is formed due to tropical and subtropical weathering in regions of plenty of rainfall, proper drainage and acidic water conditions. The chemical formula of kaolinite is Al2Si2O5(OH)4. Kaolinite is layered silicate mineral having a tetrahedral sheet in which one of the alumina sheet is associated with oxygen atoms (Deer et al., 1992). Kaolinite is generally white in colour formed due to chemical weathering of aluminium silicate minerals like feldspar. The presence of iron oxide contributes to different colors (like pink, red and orange). Other than clay minerals, quartz is the most abundant non-clay mineral found in shale. It is an essential component of sedimentary, igneous and metamorphic rocks. The chemical formula of quartz is SiO2 and is hexagonal crystal in shape.

2.5.3. Pore-structure Natural gas is primarily stored in the pore structure and porosity

system of shale gas reservoirs (Bustin et al., 2008). The empty spaces present in shales are found in inter-particle porosity and intra-particle porosity (Loucks et al., 2009). Clastic and biogenic particles contribute to the inter-particles porosity in shales by not combining properly and leaving void spaces between particles. Within the sediment particles of shales, intra-particle porosity is found. The grains or particles help in estimating the size of pores that contribute to porosity system. As per the Udden-Wentworth scale, the grain size of shale is usually below 39 μm (Wentworth, 1922). Smaller grain sizes signify presence of small size pores and shales linked to clays (Ambrose, 2011). Shale containing organic matter have grain sizes usually less than 5 μm (Sondergeld et al., 2010). Grain size along with mineralogy are important para- meters controlling pore-size distribution in mudstones (Aplin and Macquaker, 2011).

Porosity system of shale comprises of water and oil/gas (Crosdale et al., 2008). Porosity is a measure of gas holding capacity of a rock which can be defined as the empty volume within a rock in its unit volume (Schettler et al., 1989). Pore system of shales is relatively more complex than the conventional reservoirs like sandstone and limestone. The shale consists of matrix and fractures. Shale matrix consists of predominantly micropores (less than 2 nm in size) and mesopores (2–50 nm in size) as per the IUPAC classification. IUPAC further clas- sifies micropores into super-micropores (1.4–2.0 nm), micropores (0.7–1.4 nm) and ultra-micropores (< 0.7 nm) (Rouquerol et al., 1994). Micropores are of different shapes like, closed pores, blind pores, bot- tleneck pores, cross-linked pores as shown in Fig. 1. The through pores and linked pores provide pore connectivity for the gas to flow. Pores like closed and blind pores are difficult to access and such pores reduce the movement of gas in shale. Most of the pores in shales are isolated (Timur et al., 1971). Porous natural rocks (like coal or shale) contain slit-type pores that are linked by narrow capillary constrictions (Marsh, 1987). The inter-linked porosity of shales is as a result of subsequent variation occurring at the time of burial and compaction mechanisms (Amann-Hildenbrand et al., 2012). During the recent deposition of unconsolidated sediment, the porosity is higher (∼80–90%), while

Fig. 1. Different types of pore shapes.

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with deeper burial and compaction the total porosity reduces to less than 10% (Aplin and Macquaker, 2011). Diagenesis contributes to significant lowering of total porosity (Amann-Hildenbrand et al., 2012).

Macropores have lower surface area that acts as flow porosity al- lowing entry to mesopores in a rock. Likewise, mesopores performs as flow porosity thereby allowing access to microporosity. It is important to note that, capillary condensation phenomena and hysteresis (ad- sorption/desorption) in isotherms occurs in mesopores. On the other hand, micropores contributes to finer pores which have large internal surface area for storage of gas in reservoir rocks (Ross and Bustin, 2009; Amann-Hildenbrand et al., 2012). The extremely small pores in shales are associated with organic matter and clay minerals. The fractures constitute the macropores of shale. The methane adsorption in nan- ometer sized organic pores depends on surface area and is not con- trolled by size of pores (D. Cristancho-Albarracin et al., 2017). Nature of porosity in shale may influence the storage and flow mechanism of gas. In the course of gas production from shale reservoir; the micro-, meso-pores and natural fractures provides a connected pathway for the gas to flow through the induced fractures. The gas flow in shale gas systems is controlled by pore networks of shale matrix and fracture system. The fine-grained particles and small pores make the porosity estimation complicated. This in turn can create difficulty in predicting the adsorption capacity of methane and CO2 on shales. Current research on pore-structure of shales using advanced techniques such as SEM, FE- SEM, BIB-SEM, TEM, MICP, FTIR and N2 and CO2 BET have revealed the complications involved in understanding nanopore structure pre- sent in organic and inorganic part of shales (Loucks et al., 2009; Slatt and O'Brien, 2011; Chalmers et al., 2012; Klaver et al., 2012; Milliken et al., 2013).

2.5.4. Moisture Moisture is an important parameter which plays a crucial role in

storage of gas in shales. Moisture contributes to lowering gas adsorption capacity in shales due to the competitiveness existing between methane and water molecules for identical adsorption sites (Chalmers and Bustin, 2008; Ross and Bustin, 2009; Zhang et al., 2012; Gasparik et al., 2014). Moisture content in shales tend to block narrow pore throats and pore networks thereby minimizing the movement of methane molecules into micropores of organic matter (Yee et al., 1993). The interaction between both water and shale may be due to physisorption (on polar surfaces) and chemisorption (on mineral surfaces) (Gasparik, 2013). The presence of moisture in shales is mostly linked with polar clay mineral surfaces. Nevertheless, a relation between moisture and mi- cropores found in organic matter has also been demonstrated (Chalmers and Bustin, 2007). Ross (2004) suggested a correlation existing be- tween moisture content and methane adsorption capacity for Nordegg member shales samples stated as:

= +V V m(1 0.30 )d m (1)

where, Vd and Vm are adsorption capacities for dry and equivalent moisture shale samples respectively. m is the moisture content. The value of the 0.30 was compared with that of multiplier used for coal which was 0.39 for Bowen basin coal (Levy et al., 1997) and 0.31 (Ettinger et al., 1958). The multiplier 0.30 was kept lower due to the lower inherent moisture of shales than coal samples. Joubert et al. (1973) stated that when there is gradual rise in moisture content near to a critical value, after which further increase in moisture will not impact the adsorption capacity. Ross (2004) suggests that in case of shales large amount of water is adsorbed that condenses in the micropores of organic matter. Thermodynamic equilibrium is responsible for con- trolling the ability of water molecules to fill up surfaces.

2.6. Shale gas

Natural gas found in shales is formed as result of transformation of organic matter present within the shale formations. The transformation

of organic matter in sediments usually undergoes three stages that are: diagenesis, catagenesis and metagenesis (Tissot and Welte, 1984). Di- agenesis refers to the transformation of loose sediment into con- solidated sediment at shallow burial depth. During the early diagenesis stage, dead planktons in sea flows down the sea-bed to form organic mush. The living microorganisms feed upon these organic particles present in the mush. The anaerobic conditions existing deep in water do not allow animals to survive and organic mush accumulates as sedi- ment. The sediment containing dead aquatic animals get decomposed due to the pressure exerted by overlying strata as well as temperature. The diagenesis process occurs at depth up to several hundred meters. During diagenetic stage, the rise in pressure and temperature is minimal and organic matter is converted to kerogen and later the kerogen is converted into methane, carbon dioxide, water and some hetero-atomic compounds. With greater depth, at higher pressure and temperature in the range of 60–150 °C, kerogen gets converted to liquid oil, wet gas and condensate. This stage is known as catagenesis (Tissot and Welte, 1984). The conversion of organic matter to gas in shale formations mostly involves diagenesis and catagenesis.

Adsorption of methane is one of the primary mechanisms of storage of gas in shale and the same mechanism will also play an important role in potential CO2 storage in shale for the purpose of CO2 sequestration. Geological storage of carbon dioxide in shale reservoirs involves in- jecting CO2 at high-pressure such that the shale formation can perma- nently hold and prevent it from releasing to the surface. One of the advantages of storing CO2 in shale formations is that formation volume factor of carbon dioxide is greater than methane at similar pressure and temperature conditions (Tang et al., 2016). The CO2 storage capacity of organic-rich black Devonian shales, Big Sandy field, East Kentucky has been estimated to be 6.8 Gt (Nuttall et al., 2005). Tao and Clarens (2013) made an estimate of storing 10.4 Gt − 18.4 Gt of CO2 in Mar- cellus Shale by 2030. Shales with CO2 adsorption capacity of 5–10 kg/t act as promising medium for CO2 storage (Khosrokhavar et al., 2014). Edwards et al. (2015) estimated CO2 storage capacity of Marcellus Shale, Pennsylvania to be 7200–9600 Mt and Barnett Shale to be in the range of 2100 Mt to 3100 Mt. Later, it was stated that with advance- ment in technology, a significant amount of CO2 in the range of 0.9 Gt to 4.35 Gt can be stored (Boosari et al., 2015).

3. Effect of gas adsorption on shale properties

In order to model both CO2 sequestration and shale gas production, it is essential to address the concern of parameters that control CO2 and CH4 adsorption in shales. The section below summaries some of the key previous studies on adsorption of methane and CO2 on shales including the studies on shale composition. Furthermore, pore-size distribution has significant control on adsorption of gas on shales and flow behavior of gas in shale.

3.1. Methane and carbon dioxide adsorption and its relationship with shale composition

Organic matter is the key parameter that majorly contributes to gas adsorption capacity in shales. Methane adsorption capacity of shale is 10–30 times smaller than coal due to low organic matter content and complex pore structure (Chareonsuppanimit et al., 2012; Ross and Bustin, 2009). Besides, organic matter can be an appropriate site for carbon dioxide sequestration (Kang et al., 2011). Several authors have shown that organic matter in shales are nanoporous in nature which may not allow it to store CO2 in considerable amounts in free phase. However, the organics in shale possess greater internal surface area appropriate for storing adequate volume of gas in adsorbed state (Wang and Reed, 2009; Loucks et al., 2009; Kang et al., 2011; Sondergeld et al., 2010). Several studies in the past have reported positive re- lationship between TOC content and methane adsorption capacity for shales rich in organic matter (Chalmers and Bustin, 2007; Ross and

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Bustin, 2009; Weniger et al., 2010; Bakshi et al., 2018). Nevertheless, opposite trend was also reported between TOC and methane adsorption capacity for low TOC shales (Gasparik et al., 2012; Chareonsuppanimit et al., 2012). This was due to the smectite contributing to gas adsorp- tion capacity and interfering with the positive correlation of TOC and sorption capacity. Furthermore, for some Jurassic and Devonian shale samples, adsorption data at high pressures were calculated to be ne- gative (Ross, 2004; Vermylen, 2011). It was suggested that, negative adsorption data could have resulted due to fundamental problems with mass balance calculations. Negative adsorption data were found more in case of organic poor gas shales of lower adsorption capacity. Nega- tive adsorption data was attributed to the use of helium as a probing fluid for determination of void volume. Helium with a lower kinetic diameter (0.26 nm) gets access to micropores that are not available for methane (0.38 nm) which have larger kinetic diameters and the over- estimated void volume might have been responsible for negative ad- sorption data (Ross, 2004). Surface area and micropore volume are identified to be the main controlling parameters of methane adsorption capacity and these in turn are related to micropores present in the or- ganic matter of shale (Chalmers and Bustin, 2007). Thermal maturity, kerogen type, TOC content are some of the important organic matter parameters that contribute to methane adsorption capacity of shales (Chalmers and Bustin, 2008; Gasparik, 2013; Zhang et al., 2012; Ross and Bustin, 2009). Some authors have also argued the role of thermal maturity parameter on methane adsorption capacity. Positive correla- tion has been reported between thermal maturity of organic matter and adsorption capacity (Ross and Bustin, 2009; Zhang et al., 2012). This is due to the higher amount of micropores or decreasing heterogeneity in surface of pores that occurs during the conversion of organic matter. During the process of thermal maturation, the aromaticity by induced kerogen increases the methane adsorption capacity in shales. Type I and II kerogen have smaller methane adsorption capacity than that of type III kerogen (Zhang et al., 2012). Bakshi et al. (2018) suggests presence of high TOC content, type III kerogen, and the thermally mature nature suggests good hydrocarbon generation potential for the Damodar valley shales from India. Higher adsorption capacities were observed for high maturity and organic-rich shales than that of immature and organic- lean shales (Chalmers and Bustin, 2008; Gasparik, 2013; Ross and Bustin, 2009). Positive correlation was also seen between TOC-nor- malized sorption capacities and maturity (Vitrinite Reflectance, VRr) up to a value of ∼2.5%. Above a VRr value of 2.5%, the correlation was negative. It was stated that low-TOC and clay-rich shale possessed higher adsorption capacity than that of organic-rich shales (Gasparik et al., 2012).

Modeling the methane or CO2 experimental adsorption isotherm data using Langmuir or D-P or BET models is useful in extracting ab- solute adsorption characteristics (Rexer et al., 2013). Several studies have found good fitting of Langmuir model for methane adsorption data in shales (Lu et al., 1995; Nuttall et al., 2005; Chalmers and Bustin, 2008; Yuan et al., 2013; Heller and Zoback, 2014; Ji et al., 2014; El- Amin et al., 2018). Langmuir volume (VL) is directly proportional to maximum sorption capacity and this VL value contributes to surface diffusion which is a gas flow phenomenon (Cai et al., 2018). Lu et al. (1995) further proposed a bi-Langmuir adsorption isotherm model to explain adsorption in clay-rich shales. The basis of this model was bi- modal distribution of characteristic adsorption energies related to or- ganic matter and clay mineral. It was reported that the adsorption en- ergies for methane on kerogen may be higher than that of clay minerals. Ross (2004) found Langmuir model giving good fit to the adsorption data up to a pressure of 9 MPa for Nordegg Member shales from north- east British Columbia and suggested that multilayer adsorption of gas molecules takes place beyond this pressure.

Gasparik et al. (2012) proposed a modified Langmuir equation that considered the density of the sorbed phase to fit measured methane excess adsorption data satisfactorily. BET and D-P models based on the mechanism of multilayer adsorption or pore-volume filling respectively

have also been applied for gas adsorption on shales (Yu et al., 2014, 2016; Wang et al., 2015; Luo et al., 2015; Bi et al., 2016). Rexer et al. (2013) observed strong linear correlation between maximum CH4 sorption and pore volume obtained from supercritical CO2 adsorption (measured at 273 K and 195 K) for both shales and kerogen. The sorp- tion mass balances of kerogen and shale isotherms showed that ap- proximately half of the CO2 sorption in the dry shales occurred in the organic matter, while rest took place mainly in clay minerals. Lang- muir, modified Langmuir and D-R equations were used to correlate the experimental sorption data. The Langmuir equation provided good fit to experimental sorption data for both methane and CO2 than the D-R model. Later, Tang et al. (2017) reviews the existing adsorption iso- therm models useful in understanding methane sorption in shales. The adsorption models are compared based on goodness-of-fit of each model, interpreting observed test phenomena, and predicted adsorption isotherms past test data. It was reported that the adsorption models can be compared using goodness-of-fit criteria and the dual-site Langmuir model gave better fit to the experimental data than the rest of ad- sorption isotherm models. Zhou et al. (2018) combined monolayer adsorption and micropore filling theories to establish new model DA-LF model for explaining high-pressure adsorption isotherm in shale.

The potential of CO2 sequestration and enhanced recovery of me- thane from the gas shale formations depends on the preferential sorp- tion behavior of shale for CO2 over methane (Vermylen, 2011). En- hanced gas recovery (EGR) technique can be used to improve the recovery of shale gas. One alternative of EGR technique involves in- jection of CO2 into the reservoir. The injected CO2 displaces methane from shale matrix because of its preferential adsorption for CO2 and methane is produced thereby increasing the overall recovery. The in- jection of CO2 has been extensively used in coalbeds for enhanced methane recovery. Similar improvement in recovery by CO2 injection is also expected in shale gas reservoirs. Studies suggest gas shale has the ability to adsorb more CO2 compared to methane due to its preferential sorption behavior. Nuttall et al. (2005) observed that CO2 is adsorbed approximately 5 times more than that of CH4 for Devonian black shales. Weniger et al. (2010) reported CO2:CH4 adsorption ratio varied be- tween 1.9 and 6.9 for several coal and carbonaceous shale samples from Paraná Basin, Brazil. Similar study of preferential adsorption was con- ducted by Kang et al. (2011) on two Barnett shale samples from USA. It was found that CO2 adsorbed 5–10 times more than methane. The CO2 adsorptive capacity for Barnett, Eagle Ford, Marcellus and Montney shales from USA was measured to be 2–3 times higher than that of methane (Heller and Zoback, 2014). The CO2 adsorption capacity of Baltic basin shales, USA was estimated to be ∼ thrice than that of methane (Wójcicki and Jarosinski, 2017).

On the other hand, some literature also found role of clay minerals on adsorption capacity for shales rich in clay. Considerable amounts of methane adsorption have been reported for clay minerals like illite and montmorillonite (Lu et al., 1995; Schettler et al., 1991; Ross and Bustin, 2009). Generally, methane adsorption capacity of clay rich rock sam- ples varies in the sequence of “montmorillonite > > illite/smectite mixed layer > kaolinite > chlorite > illite” (Ji et al., 2012). Con- versely, it has been argued that methane adsorption in clay minerals become insignificant in moisture-equilibrated shales as surfaces of clay do possess affinity for water that prevents adsorbate molecules from entering the vacant site (Ross and Bustin, 2009). The micropores in organic fraction of Devonian–Mississippian (D–M) shales has been found to be one of the important controlling parameter for methane adsorption. The clay-rich shales have higher porosity than silica-rich samples. Thermally mature shales have larger Dubinin–Radushkevich (D–R) CO2 micropore volumes and N2 BET surface areas compared to thermally immature Jurassic shales. However, no relationship could be seen between N2 BET surface area and CO2 micropore volume for De- vonian–Mississippian shales. Positive correlation was observed between BET surface area and porosity for D-M shales suggesting porosity being influenced by mesopore structure. The clay minerals of Nordegg

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Member shales were hydrophilic in nature and organic matter content were hydrophobic in nature. Nordegg Member shales with high TOC showed higher methane adsorption capacities than organic-poor shales. Relationship between TOC and methane sorption was affected by mi- neral matter. Clay minerals like illite have micropores and are capable to adsorb gas (Ross and Bustin, 2009). On comparing both, it has been found that kerogen tends to possess higher adsorption energies com- pared to clay minerals. Exothermic heat of adsorption in pores of clay surfaces is lower than that of organic matter (Ross and Bustin, 2009). The methane adsorption capacity of organic matter is one order of magnitude greater than clay minerals (Ji et al., 2012).

3.2. Effect of pore-structure on adsorption

The heterogeneous nature of shales containing wide variety of pores (micro-, meso-, and macro-) makes the pore-structure complex. The pore characteristics such as: pore size, pore size distribution and their interconnectivity are useful in understanding the flow behavior as well adsorption of gas in shales. Pore structure of shales and its effect on gas adsorption capacity helps to predict gas in place (Pollastro et al., 2007; Loucks et al., 2009; Bustin et al., 2010). Schettler et al. (1989) initiated investigation on fine pore-structure of Devonian shales using BET and pore-filling methods to determine surface area and pore volume prop- erties. Kelvin equation was used in pore-filling measurements to esti- mate pore size (in terms of pore radius). Pore size of Devonian shales determined using adsorption techniques varied in the range of 3.4–5.5 nm. Then, Bustin et al. (2008) recommended use of combining various instrumental techniques (adsorption, nuclear magnetic re- sonance (NMR), small angle x-ray scattering (SAXS), and small angle neutron scattering (SANS)) for pore-characterization of shales. Kale et al. (2010) determined various facies types and size of pore throat of Barnett shale using mercury intrusion capillary porosimeter (MICP). The scanning electron microscope (SEM) is popularly used in estimation of pore shape and size of reservoir rocks (Loucks et al., 2009). These different techniques are classified into two categories that are radiation (e.g. SEM, SAXS, SANS) and fluid injection methods (such as: low pressure N2 and CO2 adsorption and MICP).

Micropores in shales are mostly found in organic matter and clay minerals (Slatt and O'Brien, 2011; Loucks et al., 2012; Curtis et al., 2012; Milliken et al., 2013). The micropores present in shales sig- nificantly contribute to adsorption capacity due to large internal surface area and higher adsorption energy (Dubinin, 1975; Clarkson and Bustin, 1999; Chalmers and Bustin, 2007; Ross and Bustin, 2009). In- vestigation on natural shales suggested that illite-smectite type of clays (found in shales) are associated with existence of micropores that play significant role in adsorption (Kuila and Prasad, 2011). Accordingly, Clarkson et al. (2013) investigated the pore-structure characteristics for a suite of North American shales using MICP and low pressure gas (N2 and CO2) adsorption techniques. Pore size distributions obtained from adsorption analysis were found to be either uni- or multi-modal. Except for Barnett shale, pore size data for rest of the samples showed agree- ment between adsorption and Hg data. Differences observed in the pore-size distributions obtained from gas adsorption and mercury in- trusion was due to the grain compression occurring at high pressure in Hg intrusion. Moreover, mercury intrusion provides information about pore throat and not pore body (Clarkson et al., 2013; Hinai et al., 2014). A combination of low pressure nitrogen adsorption, mercury por- osimetry and gas expansion techniques would provide more accurate pore size information about the entire pore-size spectrum of shales (Labani et al., 2013).

The organic matter contributes to 31%–62% of total porosity in which micropores adds to 50%–60% of total surface area (Tian et al., 2013). Vitrinite contributes to high methane adsorption capacity at- tributed by high micropore volume values than that of inertinite and liptinite (Unsworth et al., 1989; Chalmers and Bustin, 2007). The pore structure of shale and thermal maturity are correlated relative to

variations in porosity and pore system of kerogen (Chalmers and Bustin, 2007; Loucks et al., 2009; Bae et al., 2010). Thermal maturity con- tributes to rise in micropores in organic part of reservoir rocks (Gan et al., 1972; Bustin and Clarkson, 1998; Prinz and Littke, 2005). The increase in thermal maturity and microporosity in shales contributes to rise in methane sorption capacity (Yee et al., 1993; Levy et al., 1997; Chalmers and Bustin, 2007). The variation in organic matter presents variation in porosity even if thermal maturity remains same. Curtis et al. (2011) suggest that this is due to the origin of organic matter controlling the tendency of formation of pore structure. It was reported that kerogens in closer proximity under same environment exhibit variation in pore structure. Rexer et al. (2013) observed strong linear correlation between maximum CH4 sorption uptake and pore volume obtained from supercritical CO2 adsorption (measured at 273 K and 195 K) for Posidonia shales and kerogen. The sorption mass balances of kerogen and shale isotherms showed that approximately half of the CO2 sorption in dry shales occurred in the organic matter, while the rest took place mainly in clay minerals. Tian et al. (2013) reported that TOC values indicated positive relationships with total porosity, total surface area and micropore volume for Lower Silurian black shales in Chuan- dong Thrust Fold Belt, southwestern China. The pore-size distributions derived from the Barrett-Joyner-Halenda (BJH) and Density Functional Theory (DFT) methods suggested that pore volumes and specific surface areas were controlled by larger pores and smaller pores respectively.

Nature and origin of porous shales contributes to mineralogy (Aplin and Macquaker, 2011). However, when total gas storage is considered, mineral matter content tends to have negative correlation with gas adsorption capacity (Chareonsuppanimit et al., 2012). Bustin et al. (2008) found positive relationship between total porosity and clay for few shales from Muskwa Formation. Porosity and permeability of shales rich in clay were higher than that of silica-rich shales. This is due to the presence majority of micropores in matrix of clay mineral (Ross and Bustin, 2007). However, silica-rich shales tend to have lower mesopores and micropores (Bustin et al., 2008). The pure clay minerals exhibit lower gas adsorption capacity in comparison to organic material (Ross and Bustin, 2009; Ji et al., 2012; Gasparik, 2013). Methane sorption capacity of pure clay minerals (illite, kaolinite and montmorillonite) have been reported to be < 3 cc/g, while that of kerogen to be > 22 cc/g (Zhang et al., 2012). In highly matured shales, majority of smectite transforms to illite which thereby increases the gas adsorption capacity (Ross and Bustin, 2009; Gasparik, 2013). The specific surface area of micropores is highest in siliceous shales and pore volume is dominated by mesopores for carbonaceous shales. Organic matter (in- volving micropores) and quartz (comprising mesopore and macropore) contribute to the porosity of shale. The higher clay mineral content does not contribute to porosity including microporosity (Ye et al., 2017). Clay minerals present in shale samples are responsible for enhanced adsorption and different clay minerals possess varying methane ad- sorption capacity values (Jiang et al., 2016).

4. Conclusions

This study summarizes the existing knowledge on shale adsorption using methane and CO2 with implications on shale gas recovery and CO2 storage. Discussion on storage mechanism of gas in shales which includes adsorption isotherms and geological controls of shale gas plays are provided. Further the published literature containing findings (both qualitative and quantitative) of gas adsorption in shale and its char- acterization with respect to composition and pore-structure is sum- marised. This review provides insights into the following crucial points as listed below:

• Shale gas is being commercially produced from nations around the world, like USA, China, Canada and Argentina. Several other countries such as UK, Australia, Poland, etc. are actively involved in exploration and are in the different stages of development of shale

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gas resource.

• Shales adsorb larger volume of CO2 compared to methane at similar pressure and temperature conditions. Gas shale has the ability to adsorb more CO2 compared to methane due to its preferential sorption behavior. Langmuir isotherm model is the most common model used to describe adsorption of methane and CO2 on shales. It usually gives good fit to methane and CO2 adsorption data on shales. However, some exceptional trends have also been reported. Studies on applicability of Dubinin- Polanyi and BET models are rare for shales. Only a few researchers have tried it and observed that the D- P model gave good fit to the experimental data.

• TOC and mineral matter contribute significantly to adsorption of methane on shales. However, a few studies have also observed no correlation between adsorption capacity and TOC of shales. Clay minerals are positively correlated to methane adsorption capacity.

• The effect of pore-structure on gas adsorption capacity needs to be clearly understood and the outcomes of past studies vary widely depending on the type of shale. Uni- and bi-modal pore-size dis- tribution was reported by some researchers. Micropores present in TOC and clay minerals show positive correlation with adsorption capacity.

However, some questions still remain unanswered in the review which can add significant value to the scientific understanding of the shale-gas system.

• Majority of the studies focus adsorption for pure gas components, while on mixed gas sorption studies in shales are rare. Some pre- vious studies indicate binary gas adsorption isotherms show dif- ferent results.

• Desorption study on shales provides better understanding on the shale gas recovery phenomena. Both adsorption and desorption re- sult will provide considerable information on sorption hysteresis and its implications on shale gas recovery and CO2 sequestration.

• In most of the CO2 sequestration reservoirs, carbon dioxide exists in super-critical condition and more studies should be addressed on super-critical carbon dioxide adsorption in shale.

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