Shale is a laminated or fissile [
26] fine-grained detrital sedimentary rock, formed by the consolidation of clay, silt, or mud (
Figure 1) [
27]; it is also the most abundant sedimentary rock on Earth [
28,
29,
30]. In rock mechanics, shale can be defined as a rock where clay minerals form the load-bearing framework [
31,
32,
33]; however, strictly speaking, freshly deposited clays are not shale. The lithological properties of shale (e.g., the textural properties, elevated capillary entry pressure, and ductility) are mostly controlled by the shale’s mineralogical composition [
34]. Moreover, shales are highly inhomogeneous and anisotropic due to their fine laminations and the constitutions of different clay minerals.
2.1. Mineralogical Properties of Shales
The complex and wide variety of composition types among shales can be attributed to their different sources (i.e., different rocks, reliefs, and climate), the degree of weathering (decomposition from the source rock and during transportation), the end-product of weathering and chemical interactions, and biochemical additions [
26,
35]. Moreover, the alteration of some clay minerals occurs due to chemical diagenesis with an increase in burial depth, creating greater complexity in shale composition. The composition of shale is dominated by clay minerals, which are mostly hydrated aluminium silicate with some replacement by iron and magnesium. Typical minerals in shale include (e.g., [
26]) the following:
Kaolinite []
Smectite/montmorillonite []
Illite []
Chlorite [~]
Quartz []
Potassium/plagioclase feldspars [].
Other minerals include biochemical carbonates (e.g., calcite, dolomite) along with iron-bearing minerals (e.g., pyrite, siderite, and hematite). The presence of organic carbon makes certain shale formations potential petroleum (oil/gas) sources and/or reservoirs (gas shale). The exchange of cations in shales commonly occurs in clay minerals, which can be classified by their layered lattice structures. Two-layer (1:1) lattice structures contain one tetrahedral and one octahedral layer (
Figure 2), whereas three-layer (2:1) lattice structures are made of one octahedral surrounded by two tetrahedral layers (
Figure 3). These layer units are linked together by water or cations. The layer charge depends upon the substitution of cations in the tetrahedral or octahedral sheets [
36]. Kaolinite group minerals generally have no (or very little) layer charge, whereas illite typically has a layer charge of less than 1 (0.7–0.9 per O
10(OH)
4). Smectite possesses a layer charge between 0.2 and 0.6 per O
10(OH)
4. Kaolinite is known as a neutral mineral, and its interlayer spaces are tightly bounded by hydrogen bonds, extending from exposed hydroxyl ions in the octahedral sheet of one layer to the oxygen layers in the tetrahedral sheet of the next layer. Almost no ionic replacement occurs at either the tetrahedral or the octahedral sheets in kaolinite.
In illite, the interlayer space is also bonded by two layers of water and large K+ ions, which are not easy to substitute. On the other hand, the interlayer space in smectite generally contains two layers of water and exchangeable cations (Na+, Ca+2). Due to the low layer charge in smectite, the smectite expands when it comes in contact with fluids with higher fluid activities and is substituted by the cation of preference (e.g., Ca+2 can be replaced by Na+). Smectite lattices shrink when native Na+ is replaced by K+ in its interlayer space.
Therefore, the cation exchange capacity depends on the degree of layer charge and chemical ability to exchange the cation in the interlayer space by foreign cations. The cation exchange capacity (CEC) of clay minerals ranges from 1–10 mequ/100 g for kaolinite to 80–150 for smectites and 120–200 for vermiculites [
39]. Depending on the mineralogical composition of shale, its CEC values can differ significantly. However, cationic substitution takes place not only in the interlayer space but also at the tetrahedral or octahedral layer’s lattice. The transformation of clay minerals depends on the cationic transformation/exchange in the layer’s lattice, which appears to occur with exposure to appropriate conditions (e.g., pressure, temperature, and presence of a solution). As mentioned, shales also contain organic carbon. Most shales contain a small percentage (typically less than 10%) of organic matter. Organic matter is a source for a higher porous area within low porosity shales, but this porosity depends on the maturity of the organic matter.
2.2. The Petrophysical and Mechanical Characteristics of Shale
The petrophysical properties of shale include, among others porosity, permeability, grain size and shapes, and a specific surface area. The two most important parameters are porosity and permeability. Pore space (intrinsic void or fractures) are the storage sites for gas/liquid. The porosity of freshly deposited mud can be as high as 70% [
40] and can be reduced to about 30% beyond a few hundred meters depth [
41] and as low as below 10% at larger depths [
42,
43]. The porosity of shale depends on the depth of its burial (compaction), as well as its mineralogical composition, texture, and degree of diagenesis. The connective pores, along with existing fractures, create the pathway for fluid migration and thus contribute to the permeability of the rock. The physical and chemical interactions of fluids with shale strongly depend on the shale’s porosity and permeability. Therefore, it is worthwhile to understand permeability when analysing any effect of fluid (such as CO
2) on argillaceous rocks, such as shale. Unfortunately, it is very difficult to achieve reliable permeability measurements for shales, given their fine pore sizes and complex structures [
35,
44,
45]. In addition, the permeability relative to different fluids (gas or liquids) is different for the same rock sample. Shales exhibit very low hydraulic permeability, and this value varies widely, ranging from nanoDarcy (nD) to microDarcy (µD) [
46]. The equation derived by Kozneny [
47] and later modified by Carman [
48] indicates that permeability is a function of porosity, fluid viscosity, grain size and shape, tortuosity, the pressure gradient across a cross-section, and the specific surface area. However, for CO
2 storage integrity, scale-dependent permeability may be worthy of note. Many laboratory-derived permeability measurements underestimate the large (reservoir) scale permeability [
49], which can be attributed to the existence of fractures and non-clay minerals [
45]. Scale dependency has also been reported by several authors (e.g., Bredehoeft et al. [
50], Rudolph et al. [
51], and Keller et al. [
52]). However, Neuzil [
45] showed that the permeability scale-dependence in argillaceous rocks is not present at an intermediate scale, but it may be present at very large regional scale. It is also important to study the fracture network of the sealing material since there is field evidence (e.g., [
53]) of fluid movement through fracture networks, which may even lead fluids all the way up to surface (e.g., Bond et al. [
54], Ingram and Urai [
55], and Lewicki et al. [
56]).
A few more physical or mechanical characteristics of shales are worthy of mention, such as capillary entry pressure, strength, stiffness, acoustic velocity and anisotropy [
57] (acoustic and strength), wettability, etc. As mentioned earlier, capillary entry pressure is one of the most important properties to ensure that shale is sealed and to quantify the maximum height of the injected CO
2 column that can be held in the reservoir [
34,
58,
59]. A higher capillary entry pressure of shale restricts the movement of the fluid (e.g., CO
2), which in turn restricts the available space for the fluid to react with the shale [
59]. The potential leakage of CO
2 through caprock could occur by diffusion, capillary breakthroughs, or by fracture flow; among these mechanisms, the latter two dominate [
60,
61,
62]. These seepages could create potential available space for CO
2–shale interactions inside the shale formation (the seal), in addition to the contact area between the seal and the reservoir. The capillary entry pressure is directly related to the permeability of the shale material, the interfacial tension between the shale wetting fluid and the non-wetting fluid, and the cation exchange capacity [
63]. The very low permeability, very small pore throat radius, and higher cation exchange capacity of the shale contribute to a very high capillary entry pressure for any non-wetting fluid to enter into the generally water-wet shale [
55,
63,
64]. The fluid-flow and fluid-recovery efficiency in shale reservoirs can also be affected by shale wettability [
65,
66,
67]. However, the wettability of shale is still ambiguous, ranging from oil-wet to water-wet [
66]. This can be modified by the interplay of various factors, such as pH, temperature, and surface access [
67]. Since fine-grained sediments (mud/shale) are deposited in a marine environment, the shale is expected to be water-wet [
68]. However, the presence of mature organic matter may cause local oil-wet patches [
69].
Among the many characterization parameters, stiffness, strength, and acoustic velocities will be briefly discussed in this review article. These parameters are generally related to the porosity, density, mineralogy (mainly clay content), and heterogeneity of shale materials. Stiffness is a very important parameter in geomechanics to understand the deformability of rock and can be obtained from static (stress–strain) or dynamic (acoustic velocities) measurements. The stiffness parameter can bridge the geomechanical parameters and seismic parameters (velocity). The number of stiffness parameters needed to define a rock depends on the rock’s anisotropy. For an isotropic linear elastic material, only two parameters are required to characterize the material: Young’s modulus and Poisson’s ratio or the shear and bulk moduli. However, when the material is anisotropic, the number of stiffness parameters increases significantly (to a maximum of 81). However, shale can be approximated as a transversely isotropic (TI) material where the properties of the rock are similar in two horizontal axes (x- and
y-axis) but different from its vertical axis (
z-axis) (e.g., x = y ≠ z). The number of the stiffness parameter in the case of TI is 5 (for more details, see Fjær et al. [
31]). Very few articles have reported the effects of CO
2 on stiffness parameters. Both the Young’s modulus and Poisson’s ratio were investigated by Agofack et al. [
70] and Espinoza et al. [
71], but only changes in Young’s modulus was reported by Lyu et al. [
72]. More detailed discussions on CO
2‘s effect on shale stiffness are presented in
Section 5.2.
The strength of the shale is very important, not only to understand how difficult the shale is to break but also for seal integrity evaluation, well planning, wellbore stability, reservoir compaction, and surface or sea floor subsidence, which has been found to be sensitive to the internal properties of rock or external factors such as composition, organic content, pore pressure, and stress history (e.g., Dewhurst et al. [
42]). The strength of shales varies with the direction of measurement (anisotropy), e.g., shales are the strongest at 0° with the bedding direction (measuring the strength across the bedding) and are the weakest at 45–60° with the bedding direction. Strength parameters include UCS (unconfined compressive strength), shear strength, and tensile strength. For more discussions, with a few examples of the effects of CO
2 on shale strength, please see Section 0.
Anisotropy is one of the most widely studied properties (yet to be understood perfectly) of shale. When a rock property (e.g., strength, acoustic velocity, or permeability) varies with the direction of measurement (angle of measurement) with respect to a fixed orientation (e.g., bedding), the sample is said to be anisotropic in that property (e.g., it can have velocity anisotropy or fracture anisotropy). Shales show two types of anisotropy: intrinsic (lithological anisotropy, developed from the preferred orientation of platy clay minerals and the development of thin lamination) and stress-induced anisotropy (anisotropy developed with an increase in stress). There are many articles in the literature discussing strength anisotropy (e.g., Jin et al. [
73], Fjær and Nes [
74]), where the variation of the strength of the rocks with the angle creates problems, especially in inclined wells (e.g., borehole stability). Few researchers have discussed the effects of stiffness, strength, acoustic velocity, and even fracture anisotropy on CO
2 storage or seal integrity. Bond et al. [
54] discussed the influence of fracture anisotropy on CO
2 flow. Cheng et al. [
75] and Armitage et al. [
76] investigated the effects of permeability anisotropy on buoyancy driven CO
2 flow. Al Ismail et al. [
77] investigated the effects of CO
2 adsorption on permeability anisotropy. Taheri et al. [
78] made an attempt to investigate the effects of anisotropy and heterogeneity in both the horizontal and vertical directions of layering on the CO
2 dissolution in a saturated porous medium with brine using simulation methods. Lu et al. [
79] reported anisotropic strain in response to CO
2 injection, where the strain is always smaller in the direction parallel to the bedding plane.