Abstract Mudstones (shales) are of particular importance as the source rocks for oil and gas, and increasingly so as the reservoirs for unconventional hydrocarbons. They are also the most common sedimentary rocks on Earth, and, hence, are frequently encountered in excavations and foundations for buildings. These factors point to a pressing need to develop an increased fundamental understanding of their geomechanical and petrophysical properties. The mineral content of mudstones has a dominant effect on their mechanical properties. Presence of clay minerals within them results in plasticity and ductility that can pose particular engineering challenges, but swelling clays in particular can lead to serious problems of mechanical stability of boreholes and in construction. Good hydraulic fracture performance is linked to brittleness and high elastic moduli. This in turn is favoured by high silica or carbonate content and diagenetic cementation. Permeability to fluids depends on the interconnectivity of storage pores through orientated crack networks. New advances in imaging technologies are permitting very-high-resolution three-dimensional imaging down to the nanometre scale. Such studies will eventually lead to technological advances that exploit more effectively these enigmatic rocks.

Abstract Porosity of shales is an important parameter that impacts rock strength for seal or wellbore integrity, gas-in-place calculations for unconventional resources or the diffusional solute and gas transport in these microporous materials. From a well section obtained from the Mont Terri Underground Rock Laboratory in St Ursanne, Switzerland, we determined porosity, pore size distribution and specific surface areas on a set of 13 Opalinus Clay samples. The porosity methods employed are helium-pycnometry, water and mercury injection porosimetry, liquid saturation and immersion, and low pressure N 2 sorption, as well as small-angle to ultra-small-angle neutron scattering (SANS–USANS). These were used in addition to mineralogical and geochemical methods for sample analysis that comprise X-ray diffraction, X-ray fluorescence, total organic carbon content and cation exchange capacity. We find large variations in total porosity, ranging from approximately 23% for the neutron-scattering method to approximately 10% for mercury injection porosimetry. These differences can partly be related to differences in pore accessibility, while no or negligible inaccessible porosity was found. Pore volume distributions between neutron scattering and low-pressure sorption compare very well but differ significantly from those obtained from mercury porosimetry: this is realistic since the latter provides information on pore throats only, and the two former methods on pore throats and pore bodies. Finally, we find that specific surface areas determined using low-pressure sorption and neutron scattering match well.

Abstract A combination of permeability and ultrasonic velocity measurements allied with image analysis is used to distinguish the primary microstructural controls on effective-pressure-dependent permeability. Permeabilities of cylindrical samples of Whitby mudstone were measured using the oscillating pore-pressure method at confining pressures ranging between 30 and 95 MPa, and at pore pressures ranging between 1 and 80 MPa. The permeability–effective pressure relationship is empirically described using a modified effective pressure law in terms of confining pressure, pore pressure and a Klinkenberg effect. Measured permeability ranges between 3 × 10 −21 and 2 × 10 −19 m 2 (3 and 200 nd), and decreases by approximately one order of magnitude across the applied effective pressure range. Permeability is shown to be less sensitive to changes in pore pressure than changes in confining pressure, yielding permeability effective pressure coefficients (χ) between 0.42 and 0.97. Based on a pore-conductivity model, which considers the measured changes in acoustic wave velocity and pore volume with pressure, the observed loss of permeability with increasing effective pressure is attributed dominantly to the progressive closure of bedding-parallel, crack-like pores associated with grain boundaries. Despite only constituting a fraction of the total porosity, these pores form an interconnected network that significantly enhances permeability at low effective pressures. Supplementary material: A CSV file containing all experimental conditions and a tabulation of results is available at https://doi.org/10.6084/m9.figshare.c.3785741

Abstract Conductivity of fluids along fractures in all rocks is reduced by increasing normal stress. For sandstones and other hard rocks the onset of shear failure along planar cracks is thought to enhance fluid flow owing to a small amount of dilatancy, yet such effects are poorly quantified. Here we determine experimentally how independently increasing normal and shear stress affects fluid flow along fractures in shale. Gas flow along bedding-parallel planar interfaces was measured for flow parallel and normal to the shear direction. Increasing shear stress causes accelerating reduction of conductivity, even before the onset of macroscopic slip. Such reduction in fluid flow rate is non-recoverable, and the combined effects of normal and shear stress can reduce fracture conductivity by more than 3 orders of magnitude over the range of shale reservoir conditions. Bedding plane-parallel slip is common in shales; it can result in a large enhancement of permeability anisotropy, because flow across bedding planes becomes inhibited. This can impact upon the geometry of developing hydraulic fractures, encouraging complexity and favouring lateral relative to vertical growth. The results will facilitate modelling of fluid flow through fracture networks. Supplementary material: A CSV file containing all experimental conditions and tabulations of results is available at https://doi.org/10.6084/m9.figshare.c.3721831 .

Abstract Opalinus Clay (OPA) is considered as a potential host rock for the deep geological disposal of radioactive waste. One key parameter in long-term storage prediction is permeability. In this study we investigated microstructural controls on permeability for the different facies of OPA. Permeability and porosity were determined under controlled pressure conditions. In addition, the pore space was investigated by SEM, using high-quality surfaces prepared by broad ion beam (BIB) milling. Water permeability coefficients range from 1.6 × 10 −21 to 5.6 × 10 −20 m 2 ; He-pycnometer porosities range between approximately 21 and 12%. The sample with the highest He porosity (shaly facies) is characterized by the lowest permeability, and vice versa (carbonate-rich sandy facies). This inverse behaviour deviates from the generally reported trend of increasing permeability with increasing porosity, indicating that parameters other than porosity affect permeability. Visible porosities from SEM images revealed that 67–95% of the total porosity resides within pores smaller than the SEM detection limit. Pore sizes follow a power-law distribution, with characteristic power-law exponents ( D ) differing greatly between the facies. The carbonate-rich sandy facies contains a network of much larger pores ( D (shaly) ≈2.4; D (carbonate-rich) c. 2.0), because of the presence of load-supporting sand grains that locally prevent clay compaction, and are responsible for a higher permeability.

Abstract In order to characterize the stress-dependence of porosity and permeability of Bossier shale, a series of measurements was conducted on three dry, horizontally orientated samples using various gases under controlled stress conditions. The Klinkenberg-corrected permeability and gas slippage factors varied by more than two orders of magnitude (0.21–86 µD) and by one order of magnitude (0.09–0.89 MPa), respectively. Porosity values measured under in situ stress conditions were lower by up to 30% than those measured at ambient conditions. Therefore, disregarding the stress-dependence of porosity may lead to a substantial overestimation of the free gas storage capacity. The stress sensitivity of Klinkenberg-corrected permeability coefficients (−0.012–−0.063MPa −1 ) is much larger than the stress sensitivity of porosity (−0.0014–−0.0033 MPa −1 ). Particularly for pore systems dominated by microfractures or slit-shaped pores, the permeability is highly sensitive to effective stress changes. While conventional pore models use porosity stress-sensitivity exponents ( m ) ranging between 3 and 5, we measured values of up to 27. Strongly stress-sensitive permeability behaviour is a result of effective stress preferentially reducing the volume and effective cross-section of transport pathways. In contrast, stress-dependent permeability of a less stress-sensitive sample is instead controlled by the redistribution of flow.

Abstract A series of controlled water and gas experiments was undertaken on samples of Callovo-Oxfordian (COx) mudstone using a synthetic fluid and helium gas. Data from this study demonstrate that the advective movement of gas through COx is accompanied by dilation of the original fabric (i.e. the formation of pressure-induced microfissures) at gas pressures significantly below that of the minimum principal stress. Flow occurs through a local network of unstable pathways, the properties of which vary temporally and spatially within the mudstone. The coupling of variables results in the development of significant time-dependent effects affecting many aspects of COx behaviour, from the gas breakthrough time to the control of deformation processes. Variations in gas entry, breakthrough and steady-state pressures may result from the arbitrary nature of the flow pathways and/or microstructural heterogeneity. Under these conditions, the data suggest that gas flow is along pressure-induced preferential pathways, where permeability is a dependent variable related to the number, width and aperture distributions of these features. This has important implications for modelling gas migration through low permeability, clay-rich materials.

Abstract The transport of dissolved CO 2 in brine through a smectite-rich shale-type cap rock above a CO 2 storage reservoir may lead to the adsorption of CO 2 in the smectite and the associated swelling of this material. These effects on the cap-rock permeability and on the stress in the cap rock have been modelled by combining single-phase two-species convective–diffusive flow with poro-elastic effects. We assume that the cap rock behaves as a poro-elastic, uniform and isotropic rock with two intermingled networks of macropores and of interlayer space between the clay layers. The empirical expressions for the chemical potentials and partial molar volumes of water and CO 2 in the macropores and in the interlayer space have been derived from experimental data. With an emphasis on the physics underlying clay swelling, we have applied the model for uniaxial deformation in a cylindical symmetrical geometry. Considering that this geometry is, to some extent, only representative of the geometry at a reservoir edge, and that anisotropy, plasticity and a possible permeability increase when the stress in the rock is close to shear-type failure have not been included in this work and recognizing the present uncertainties in the experimental clay and shale data, the results are indicative. The model predicts that the stresses following CO 2 adsorption in a smectite-containing cap rock are substantial at typical subsurface conditions for a carbon capture and storage (CCS) project. When the rock is under an unfavourable stress condition, local shear-type failure may occur in the cap rock exposed to CO 2 over a period of 100–10 000 years, despite the fact that the permeability of the rock may reduce under the increasing compressive stress. For this reason, we recommend including the possibility of swelling cap rock into a containment risk assessment of a CCS project.

Abstract As the fastest growing energy sector globally, shale and shale reservoirs have attracted the attention of both industry and scholars. However, the strong heterogeneity at different scales and the extremely fine-grained nature of shales makes macroscopic and microscopic characterization highly challenging. Recent advances in imaging techniques have provided many novel characterization opportunities of shale components and microstructures at multiple scales. Correlative imaging, where multiple techniques are combined, is playing an increasingly important role in the imaging and quantification of shale microstructures (e.g. one can combine optical microscopy, scanning electron microscopy/transmission electron microscopy and X-ray radiography in 2D, or X-ray computed tomography and electron microscopy in 3D). Combined utilization of these techniques can characterize the heterogeneity of shale microstructures over a large range of scales, from macroscale to nanoscale ( c. 10 0 –10 −9 m). Other chemical and physical measurements can be correlated to imaging techniques to provide complementary information for minerals, organic matter and pores. These imaging techniques and subsequent quantification methods are critically reviewed to provide an overview of the correlative imaging workflow. Applications of the above techniques for imaging particular features in different shales are demonstrated, and key limitations and benefits summarized. Current challenges and future perspectives in shale imaging techniques and their applications are discussed.

Abstract High-resolution water sorption isotherms were measured on 13 representative mudrock samples in order to assess the mechanisms of water vapour sorption and their relationship to the pore structure of mudrocks. The isotherm measurements were performed at 303 K on a gravimetric, dynamic vapour sorption device. Experimental data were interpreted by traditional physisorption models for which the validity was evaluated by relating model parameters to those obtained from nitrogen physisorption measurements. No direct relationships with the pore structure were observed, except for the Gurvich total pore volumes and the corresponding porosity data. Specific surface areas from Brunauer–Emmett–Teller theory are ambiguous and do not relate to nitrogen data, suggesting that water molecules do not adsorb as (multi-) layers covering pore walls. The volume filling theory (Dubinin–Astakhov equation) fits the water sorption data well but no relationship to the nitrogen data was observed in the studied sample set. A lower affinity of water for micropores was evident from the higher filling pressures of N 2 -based micropore volumes. The Barret–Joyner–Hallenda theory combined with N 2 physisorption measurements on moist mudrocks revealed that capillary condensation prevails close to saturation but not below about 0.94 relative pressure ( p / p 0 ). A distinct low-pressure hysteresis was observed from hysteresis scanning that was attributed to surface chemistry since capillary condensation occurs only at very high relative pressures. Analysis of mineralogical composition, total organic content (TOC) and organic maturity in relation to water sorption revealed only a weak correlation with the total clay content. In contrast, cation-exchange capacity (CEC) strongly correlates with water uptake, which evidences a surface-chemistry-controlled sorption mechanism. Tests of the influence of the exchangeable cation were inconclusive because pore system alteration due to cation-exchange probably superimposed the effect. To further assess the sorption mechanisms of water, nitrogen physisorption isotherms were measured on moisture-equilibrated mudrocks (11, 52, 75, 94% relative humidity at 298 K). Micropore analysis and cumulative pore-size distributions denote that water blocks pore throats rather than fills pore volumes at lower relative humidities. Over the entire humidity range, no direct relationship between water sorption and pore size was observed. These findings imply that water adsorption does not sequentially fill pores with increasing radii in mudrocks as relative humidity increases, as would be expected from water sorption by capillary condensation. This conclusion has important implications for the interpretation and measurement of geomechanical and petrophysical properties of mudrocks. Capillary pressures, particularly at low water saturations, are often calculated from water saturation using a concept based on the Kelvin equation for capillary condensation. Since water sorption in mudrocks seems to be controlled by surface chemistry rather than pore size, this approach is questionable. The observations reported here suggest that the water distribution in mudrock pore systems resulting from vapour equilibration differs from that obtained by fluid displacement (i.e. capillary drainage or imbibitions). A further consequence is that water vapour equilibration is a convenient, but not necessarily representative, method to obtain partially water-saturated mudrock samples for laboratory measurement of saturation-dependent geomechanical or petrophysical properties.

Abstract Lower than anticipated gas production rates in coal bed methane (CBM) operations are sometimes related to formation damage in which reduced permeability results from the interaction of bore and fracturing fluids with coal. This study assesses the potential for mineral precipitation to cause formation damage from a Permian coal seam in the Bowen Basin, eastern Australia, using geochemical modelling of coal mineralogy, formation fluid and bore fluid composition. The mineralogical composition of coal was assessed using petrography, X-ray diffraction, X-ray fluoresence and electron beam microanalysis. Geochemical modelling of ambient groundwater and drilling fluid interactions with coal samples was undertaken using Geochemist’s WorkBench (GWB). This modelling indicates that likely mineral precipitates/re-precipitates to adversely impact porosity and permeability include a range of clay, carbonate and sulphate minerals. Additionally, these interactions may induce alteration of precursor smectites to new species that reduce permeability. The resultant smectites also have a high propensity for expansion and dispersion in the presence of inappropriate drilling fluids. Precipitation, expansion and dispersion of these fine-grained minerals may potentially lead to large reductions in permeability, with profound impacts upon gas flow. Indications are that reduced permeability can be mitigated by suitable chemical matching of groundwaters with drilling fluids.

Abstract It is generally accepted that the clay mineralogy of the shale formation is a primary causative factor of shale instability. This review considers a scenario of shale instability relating to illitic minerals. From the literature the thickness of the double electric layer (DEL) of the aqueous solutions associated with the charged external surfaces of clay minerals is of the same order or even thicker than the sizes of a significant proportion of the pores found in shales. In these circumstances, overlap of the DELs associated with the exposed outer surfaces of clay minerals on opposing sides of slit-like micropores (<2 nm in diameter) and mesopores (2–50 nm in diameter) in a lithostatically compressed shale would bring about electrostatic repulsion and lead to increased pore/hydration pressure in illitic shales. In shales and sandstones, illitic material is usually described in terms of two different phases, namely illite per se and mixed-layer illite–smectite (I/S). Evidence is presented to show that it is often the case that only one illite phase exists and that in reality the mixed-layer I/S is simply very thin illite (<5 nm in thickness) in the early stages of its growth. Such material is of common occurrence in the unconventional hydrocarbon reservoirs of the USA.

Abstract Mudrocks comprise fine-grained, sediments, in which the modal grain size is <0.063 mm and clay minerals are often major constituents. In geotechnics the term defines a generic group of argillaceous lithologies ranging from stiff clay-soils to strong, partly metamorphosed rocks. In the UK outcrops occur extensively and they also lie concealed beneath later deposits. In engineering applications mudrocks can present challenging forms of behaviour, including rapid deterioration and structural breakdown during sampling and preparation for tests. Attempts to measure their geotechnical properties are often frustrated and misleading results appear in the literature. A review of the engineering properties of UK mudrocks and studies involving mudrocks of varying induration demonstrates the importance of composition and genesis in controlling physical behaviour and provides a framework for understanding variation in mudrocks. Various index tests have been appraised in terms of their value for predicting mudrock durability. It is newly proposed that style of breakdown provides guidance for predicting the mechanical properties and that simple index tests can supplant relatively expensive and time-consuming undisturbed sampling and testing, even where this is possible. This approach has potential for use in the prediction of fracture formation owing to changes in stress conditions and pore water pressure.

Abstract Fracture toughness was measured for a range of rock materials as a function of temperature between ambient temperature and 150°C. Measurements were made along all three principal crack orientations for the transversely isotropic Mancos shale and in single orientations for the more isotropic Darley Dale sandstone, Indiana limestone and Lanhelin granite. Fracture toughness was measured using a modified short-rod method with the sample and loading equipment enclosed within an elevated temperature chamber. A slight increase in K Ic was observed in Lanhelin granite with increasing temperatures up to 54°C, before a steady decrease at higher temperatures. For the sandstone and limestone, little change was observed in K Ic over the studied temperature range. In measurements on Mancos shale at elevated temperatures. Fracture toughness was seen to increase slightly with increasing temperature in the arrester orientation over this range, while remaining constant in the other two orientations. These observations can be explained in terms of the development of thermally induced microfractures parallel to the bedding planes in this material. A bimodal distribution of K Ic values in the short-transverse orientation was not observed, as it has been for previously published measurements at ambient conditions.

Abstract Numerical simulations of a naturally fractured shale reservoir are used to investigate the influence of sequential hydraulic fractures on the shear displacements and evolving stability of a fault. The effect of the heterogeneous elastic strains arising from natural fractures and faults in the reservoir on the displacements around hydraulic fractures is simulated. The displacements experienced by the hydraulic fractures depart strongly from the elliptical distribution characteristic of homogeneous elastic media, and are a result of the influence of natural fractures and faults by both superposition of elastic strains and inelastic behaviour. It is shown that interaction between the pre-existing reservoir strains and those induced by hydraulic fracturing influence shear displacements along the fault. Displacements on the fault respond to the hydrofracture-induced shear strains, tend to be restricted to certain patches of the fault and mainly tend to stabilize the fault. The results imply that the numerous closely spaced hydraulic fractures characteristic of current shale reservoir completion practice may, to some extent, increase the stability of potentially unstable faults before they are intersected by a propagating hydraulic fracture. The stability of the fault as the fractures sequentially approach the fault depends upon the direction of approach and the dimensions of the hydraulic fractures.

Abstract By integrating multiple datasets with relevant theory, covering fluid injection and fracturing, a conceptual model has been developed for the fracture development and induced seismicity associated with the fracking in 2011 of the Carboniferous Bowland Shale in the Preese Hall-1 well in Lancashire, NW England. Key features of this model include the steep fault that has been recognized adjoining this well, which slipped in the largest induced earthquakes, and the presence of a weak subhorizontal ‘flat’ within the depth range of the fluid injection, which was ‘opened’ by this injection. Taking account of the geometry of the fault and the orientation of the local stress field, the model predicts that the induced seismicity was concentrated approximately 700 m SSE of the Preese Hall-1 wellhead, in roughly the place where microseismic investigations have established that this activity was located. A further key observation, critical to explaining the subsequent sequence of events, is the recognition that the fluid injection during stage 2 of this fracking took place at a high net pressure, approximately 17 MPa larger than necessary. As a result, the fluid injection ‘opened’ a patch of the ‘flat’, making a hydraulic connection with the fracture network already created during stage 1. Continued fluid injection thus enlarged the latter fracture network, which ultimately extended southwards far enough to intersect the steep part of the fault and induce the largest earthquake of the sequence there. Subsequent fluid injection during fracking stages 3 and 4 added to the complexity of this interconnected fracture network, in part due to the injection during stage 4 being again under high net pressure. This model can account for many aspects of the Preese Hall record, notably how it was possible for the induced fracture network to intersect the seismogenic fault so far from the injection point: the interconnection between fractures meant that the stage 1 fracture continued to grow during stage 2, rather than two separate smaller fractures, isolated from each other, being created. Calculations indicate that, despite the high net pressure, the project only ‘went wrong’ by a narrow margin: had the net pressure been approximately 15 MPa rather than approximately 17 MPa the induced seismicity would not have occurred. The model also predicts that some of the smaller induced earthquakes had tensile or ‘hybrid’ focal mechanisms; this would have been testable had any seismographs been deployed locally to monitor the activity. The analysis emphasizes the undesirability of injecting fracking fluid under high net pressure in this region, where flat patches of fault and/or subhorizontal structural discontinuities are present. Recommendations follow for future ‘best practice’ or regulatory guidelines. Supplementary material: Background information on the stratigraphy, structural geology, rock-mechanical properties of the study region and its state of stress, as well as theory for fluid injection, hydraulic fracturing and Coulomb failure analysis, is available at https://doi.org/10.6084/m9.figshare.c.3781121

A surge of interest in the geomechanical and petrophysical properties of mudrocks (shales) has taken place in recent years following the development of a shale gas industry in the United States and elsewhere, and with the prospect of similar developments in the UK. Also, these rocks are of particular importance in excavation and construction geotechnics and other rock engineering applications, such as underground natural gas storage, carbon dioxide disposal and radioactive waste storage. They may greatly influence the stability of natural and engineered slopes. Mudrocks, which make up almost three-quarters of all the sedimentary rocks on Earth, therefore impact on many areas of applied geoscience. This volume focuses on the mechanical behaviour and various physical properties of mudrocks. The 15 chapters are grouped into three themes: (i) physical properties such as porosity, permeability, fluid flow through cracks, strength and geotechnical behaviour; (ii) mineralogy and microstructure, which control geomechanical behaviour; and (iii) fracture, both in laboratory studies and in the field.