The success of hydrogen as a fuel relies heavily on the integration of renewables to the production mix. The integration of renewable energy in existing energy infrastructure requires development of suitable storage solutions along the energy supply chain. Centralized storage mediums of large scale are inevitable for yielding the maximum potential from renewables. Centralized storage of hydrogen can be achieved through underground geologic structures. This chapter details the present state of different underground storage mediums such as salt caverns, depleted hydrocarbon reservoirs, aquifers and hard rock caverns, their applications, as well as the associated technical challenges. The suitability of the geostructures depends on the desired storage cycles, capacities, and purity of stored hydrogen. The chapter also presents an overview of the factors to consider during selecting the suitable storage structures. The chapter also provides future directions to address the associated challenges and prevalent knowledge gaps for the successful utilization of subsurface geostructures for the centralized storage of hydrogen.

Particle-fluid two-phase flows in rock fractures and fracture networks play a pivotal role in determining the efficiency and effectiveness of hydraulic fracturing operations, a vital component in unconventional oil and gas extraction. Central to this phenomenon is the transport of proppants, tiny solid particles injected into the fractures to prevent them from closing once the injection is stopped. However, effective transport and deposition of proppant is critical in keeping fracture pathways open, especially in low-permeability reservoirs. This review explores, then quantifies, the important role of fluid inertia and turbulent flows in governing proppant transport. While traditional models predominantly assume and then characterise flow as laminar, this may not accurately capture the complexities inherent in real-world hydraulic fracturing and proppant emplacement. Recent investigations highlight the paramount importance of fluid inertia, especially at the high Reynolds numbers typically associated with fracturing operations. Fluid inertia, often overlooked, introduces crucial forces that influence particle settling velocities, particle-particle interactions, and the eventual deposition of proppants within fractures. With their inherent eddies and transient and chaotic nature, turbulent flows introduce additional complexities to proppant transport, crucially altering proppant settling velocities and dispersion patterns. The following comprehensive survey of experimental, numerical, and analytical studies elucidates controls on the intricate dynamics of proppant transport under fluid inertia and turbulence - towards providing a holistic understanding of the current state-of-the-art, guiding future research directions, and optimising hydraulic fracturing practices.

The impact of fluid inertia on fracture flow dynamics, particularly under high-velocity conditions, has emerged as a critical consideration in petroleum engineering and related fields. This review paper investigates the profound effects of inertia-dominated nonlinear flow, a phenomenon increasingly recognised for its significant influence on fluid dynamics in rock fractures. Given the prevalence and importance of such flows in field applications, neglecting fluid inertial effects is no longer justifiable. A comprehensive investigation into these effects is essential for advancing our understanding of fracture flow mechanisms and optimising engineering practices. This review aims to thoroughly analyse the impact of fluid inertia on applications in hydraulic fracturing. It offers an in-depth discussion of how fluid inertia affects critical aspects of crack propagation, fracture diagnostics, proppant transport and settlement, and fines migration. Additionally, this paper identifies and explores four main factors that influence the fluid inertia effect in fracture flows: fracture roughness, intersections and dead ends within the fracture network, variations in contact area and fracture aperture, and the role of shear displacement. The review provides valuable insights into the complex interplay between fluid inertia and fracture flow dynamics by elucidating these factors.

Carbon dioxide enhanced shale gas recovery (CO2-EGR) technology is of great significance for shale gas extraction and carbon dioxide storage in subsurface, which involves the competitive adsorption in shale nanopores. Adsorption comparisons between the kerogen matrix and slit and between the pure gas and gas mixture are conducted in this study. Kerogen matrix and slit models are built with the type II-A kerogen macromolecules and adsorptions of CH4 and CO2 are modelled. It is seen: 1) The gas absolute adsorption increases with its molar fraction while decreases with temperature. The Langmuir pressure for CO2 decreases while that for CH4 increases with their molar fractions. The adsorption selectivity of CO2 over CH4 decreases with the increase in pressure and the CO2 fraction, while it is higher in the matrix than that in the slit. Water significantly reduces the gas adsorption especially for matrix. 2) CO2 has high affinity to the Sulfur and Nitrogen functional groups, while CH4 molecules mainly adsorb on the Sulfur, Nitrogen and Carbon functional groups, While water are strongly bound to the Oxygen functional groups with water cluster formed at high contents. 3) Lower interaction energies are shown in the matrix compared with the slit due to the adsorption superposition, which results in gases preferentially adsorbed in the matrix then on the slit surface in the kerogen slit model. The water interaction energy is lowest due to the hydrogen bond, while the interaction energy of CO2 is much smaller than that of CH4 indicating its adsorption advantage.

A numerical study was conducted on the damage behaviors of sandstone specimens with an embedded rough fracture under triaxial stress conditions. The discrete element method was used to study the deformation and cracking characteristics, and the effects of triaxial stress state, fracture width and inclination angle on the mechanical properties were also investigated. The results are as follows: (1) The strength of fractured rock decreased with the increase of fracture width ratio and the yield stress under conventional triaxial stress is higher than those under true triaxial tests with the same mean confinement; (2) For fractured rock models with small width ratios (0.2, 0.4 and 0.6), the strength increases as the fracture angle turning towards the principal stress direction. The shear damaged bond ratio decreased with the increase of confining pressure when σx=σy , while its ratio increased slightly with the fracture angle when σx≠σy; (3) For the large-width fractured rock model with a width ratio 1.0, the strength first decreased and then increased with the increasing inclination angle. At inclination angles of 0° and 30°, damage first occurred near fracture surface, then it propagated along the diagonal direction, and the ratios of bond damage caused by tension and shear failure were almost equal. While the shear damaged bond ratio was much higher than that by tension at inclination angles of 60° and 90°.

Fluid flow in fractured rock masses is important for many engineering applications. As fluid moves through the fractures, non-negligible pressure losses occur even at a moderate flow rate where the flow velocity changes. Centrifugal forces arise where fluid flows around bends such as at fracture intersections. These velocity changes consume energy, compromising the linear relationship between flow rate and pressure drop. For the flow in individual fractures, the Forchheimer number, Reynolds number, and critical hydraulic gradients have been used to distinguish between creeping flow, weak inertia, and turbulent flow regimes, but not fracture networks because of their intricate geometry and the erratic flow inside them.This paper reviews models and approaches applied to quantify pressure losses and predicts the flow rates in fracture networks during single-phase fluid flow, trying to establish the current level of understanding of these processes. We find that while Navier Stokes simulations have been applied to analyse flows for idealized fracture geometries, studies on fluid flow in complex fracture networks are rare. This review attempts to collect available quantitative constraints on the effect of inertia on pressure and velocity distributions in fracture sets, flow partitioning between them, and energy losses along the flow path, highlighting that there is a pressing need to develop a better understanding of flow in fracture networks at realistic flow rates, considering inertia effects and resulting nonlinearities.

Fluid production from fractured rock masses readily induces fracture flow velocities of meters per second. Yet, most discrete fracture flow models treat flow as laminar creeping flow or account for inertia effects only by single-fracture constitutive relationships.This numeric simulation study investigates water flow patterns and spatial velocity variations in a natural fracture network with mm-wide open fractures, studying the transition from laminar creeping to turbulent flow. After verification with a fracture intersection model, a Reynolds-time-averaged Navier Stokes solver serves to analyse flow regimes and velocity distribution. Our results show that for fracture flow velocities greater than ∼1 cm/s, fluid inertia begins to markedly alter flow patterns and the overall velocity distribution in the network. The pressure-gradient-flow relationship therefore becomes non-linear long before the flow in straight fractures enters the weak inertia regime. This prominence of inertia effects highlights the need to improve fracture network flow models.

Sand production, a challenge in the geo-energy industry, compromises reservoir integrity and equipment by eroding and transporting sand grains from unconsolidated and weakly consolidated reservoirs, which is crucial in oil, gas, geothermal, and underground hydrogen storage systems. Effective management and accurate prediction of sand behaviors are essential for maintaining wellbore stability and optimizing energy extraction processes. This study comprehensively reviews the discrete element method (DEM) used over the past three decades for simulating sand production, a significant phenomenon causing substantial equipment damage and financial losses in the geo-energy industry. Our review elaborates on the adaptation of DEM for modeling the mechanical behavior of sandstone, sandy materials, and granular packs, which is essential for predicting and mitigating sand production. We categorize the review into five key areas—force models, bond models, damping models, particle shape, and particle size distribution. These aspects are pivotal in enhancing the realism of DEM simulations. The review critically assesses current methodologies and their limitations, emphasizing the need for precise parameter selection in DEM to yield realistic simulations, aligning with the emerging trends and technological advancements in geotechnical engineering.

This paper comprehensively reviews mechanical weakening and crack development in the caprock during underground hydrogen storage in depleted gas reservoirs. Hydrogen loss due to the geochemical interactions of hydrogen and caprock minerals critically impacts caprock integrity. As shown in the review, it is conspicuous that the mechanical properties of the caprock also change with the hydrogen injection, affecting its brittle-ductile behaviour. Furthermore, the stress–strain behaviour of the caprock is changed, and it undergoes irreversible deformations under the influence of confining pressure, cyclic loading, and changes in the mineral composition.The fracturing of the caprock is another critical impact on the storage integrity, which may create new routes for the hydrogen permeation through the caprock. Cracks may form in the caprock in multiple ways, mainly 03 ways; 1) Highly pressurized hydrogen injection creates critical cracks in the caprock when the pore pressure exceeds the fracture toughness, called critical cracks, 2) The injected hydrogen accumulates under the caprock due to gravity segregation and, eventually, diffuses into the caprock, displacing its pore fluid (brine). Consequently, capillary stress on the caprock minerals and the pores may increase with developing cracks, called shrinkage cracks, and 3) Geomechanical interaction between hydron-pore fluid-rock minerals under the biotic environment (micro-organisms) available at underground storage sites can cause mechanical properties degradation in caprock, forming new cracks under low injection pressure conditions, called sub-critical cracks.Although the critical or tensile crack formation process has been widely studied in the existing studies, minor attention has been given to other possible crack formation processes in the caprock, including the hydrogen-induced shrinkage cracking and the geomechanical reactions causing sub-critical cracking. In addition, the impact of this mechanical weakening of the caprock on its overall structure and flow characteristics hasn't been properly understood, adding extra uncertainty to the caprock's integrity during the underground hydrogen storage process.

Hydrogen has attracted attention worldwide with its favourable inherent properties to contribute towards a carbon-free green energy future. Australia aims to make hydrogen as its next major export component to economize the growing global demand for hydrogen. Cost-effective and safe large-scale hydrogen storage in subsurface geology can assist Australia in meeting the projected domestic and export targets. This article discusses the available subsurface storage options in detail by first presenting the projected demand for hydrogen storage. Australia has many subsurface formations, such as depleted gas fields, salt caverns, aquifers, coal seams and abandoned underground mines, which can contribute to underground hydrogen storage. The article presents basin-wide geological information on the storage structures, the technical challenges, and the factors to consider during site selection. With the experience and knowledge Australia has in utilizing depleted reservoirs for gas storage and carbon capture and sequestration, Australia can benefit from the depleted gas reservoirs in developing hydrogen energy infrastructure. The lack of experience and knowledge associated with other geostructures favours the utilization of underground gas storage sites for the storage of hydrogen during the initial stages of the shift towards hydrogen energy. The article also provides future directions to address the identified important knowledge gaps to utilize the subsurface geology for hydrogen storage successfully.

This study reviews rock-fluid interaction during the underground hydrogen process in depleted gas reservoirs. According to the review, although over 700 publications can be found in the literature related to rock-fluid interaction related to other deep-earth applications, only few studies have paid attention to underground hydrogen storage in depleted gas reservoirs. Rock-fluid interactions happen in various ways during underground hydrogen storage in depleted gas reservoirs, mainly: 1) geochemical interactions, called abiotic interactions, and 2) microbial activities, called biotic reactions. All these interactions are greatly affected by some physicochemical processes that occur in reservoirs during hydrogen storage, including changes in wettability, interfacial tension, diffusion, adsorption, and solubility.Hydrogen interacts with rock minerals during abiotic reactions, resulting in mineral dissolution and precip-itation and, preferably, occurs in the reservoir's reactive zone. Most abiotic reactions happen only under extreme pressures and temperatures during hydrogen storage. Biotic reactions have been identified as the major reason for the loss of hydrogen during the storage process because these happen under typical reservoir conditions (below 130 degrees C temperature and 35 MPa pressure) and create other issues. For example, the sulphate-reducing reaction creates an acidic environment and sulphide precipitation near the wellbore, causing material corro-sion and permeability reduction.Changes in wettability, interfacial tension, adsorption, diffusivity, and solubility can significantly impact rock -fluid interactions during hydrogen storage. Hydrogen wettability in reservoir rocks is much less than in other gases; therefore, a gas like nitrogen can recover trapped hydrogen during recovery. Hydrogen's absorption/ desorption characteristics are important in reservoirs with high surface areas, such as coal, and significantly change with pressure and the type of cementation material. Hydrogen solubility in brine is much less than in other gases, and in contrast, hydrogen is highly buoyant and diffusive compared to other gases. However, diffusion is critical only in the first stage of hydrogen storage, and the total diffusive loss of hydrogen in a reservoir is <2%. Rock-fluid interactions significantly affect the safety of the storage process, including caprock and wellbore integrity.According to the conducted comprehensive review study, some areas need further research for an effective underground hydrogen storage process. In particular, the combined effect of biotic and abiotic interactions on mineralogical, hydrological and mechanical properties of reservoir rocks, their impacts on wellbore and caprock integrities, hydrogen loss caused by fingering under heterogeneous reservoir conditions, the recovery possibility of residually trapped hydrogen using other gases, and rock-fluid interactions in complex reservoir rocks such as coal.

Proppant embedment in coal is highly concerned in both research and practice due to the vulnerability of the softer surface nature in coal and its involvement in fracture treatment failures. The issue has been reported to further intensify under pore fluid conditions; however, to date very few studies have investigated this effect for coal propped fractures. Analysing proppant embedment in numerical models through standard material models is far from realistic for materials like coal because the distinct plastic deformation stages play an essential role in proppant embedment measurements. In this study, a Drucker Prager material model is implemented, which employs the shrinking of the failure criteria by the progress of plastic deformation to consider the strain-softening behaviour of coal. The numerical results show that the implemented material model can describe the distinct deformation stages experienced in coal materials. The simulation results for uniaxial compression tests, triaxial tests and proppant embedment tests agree well with their experimental counterparts. However, comparing the simulation and experimental results show that modification of the elastic modulus alone to incorporate surface changes experienced due to pore fluid saturations, which is the primary parameter considered in proppant embedment studies may provide an underestimation for proppant embedment measurements in coal.

There are large amounts of nanoscale rough pores in shale, which provides the sites for methane adsorption. Proper understanding of the mechanisms of methane adsorption in nanoscale rough slits is important for estimating the shale gas reserves. In this study, graphene was used instead of shale to construct nanoscale slits with different widths and roughness, and the effects of roughness, slit width and pressure on the methane adsorption characteristics are investigated by using the GCMC and molecular dynamics methods. The results showed that the methane adsorption configurations are influenced by the slit width and surface roughness. The adsorption layers in rough slits are discontinuous and weak second adsorption layers are formed in large slits at high pressures. The inaccessible volume increases with the roughness resulting in the reduction of accessible volume. Therefore, both the excess adsorption and absolute adsorption decrease with the roughness, and they increase with the slit width in the microscopic scale due to the increased adsorption. While decrease slightly with the slit width in the mesoscopic scale due to the reduction of adsorbed phase density. The excess adsorption isotherms are well fitted by the Langmuir-Freundlich model. The adsorption is found more stable in smaller and rougher slits due to the superposition of adsorption potentials through the analysis of adsorbate potential energy and adsorption heat.

An economy based on hydrogen is widely regarded as the potential successor of the fossil-fuel-driven present energy sector. One major obstacle in developing the hydrogen economy is the suitable storage systems for different applications. This article presents an overview of the role of different storage technologies in successfully developing the hydrogen economy. It reviews the present state of various hydrogen storage systems from the surface and underground storage methods, their applications, and the associated scientific challenges. The integration of renewable energy in existing energy infrastructure requires developing suitable storage solutions along the energy supply chain. Large-scale seasonal hydrogen storage can be achieved through a subsurface geologic medium such as salt caverns, depleted hydrocarbon reservoirs, aquifers and hard rock caverns. The suitability of the geostructures depends on the desired storage cycles, capacities, and purity of stored hydrogen. The storage of hydrogen for stationary and mobile applications according to end user demands, generally less in capacity and requiring rapid storage cycles, is facilitated by surface storage methods. The physical storage of hydrogen is trapping it in vessels in its different physical states, such as compressed gaseous, cryogenic and cryo-compressed forms. Material-based storage of hydrogen is by adsorbing or absorbing hydrogen using solid-state materials. The performance of surface storage technics is characterized by gravimetric and volumetric densities, storage uptake and release kinetics, the cost involved, and operational safety. The technical insights of each storage technology are presented with recommendations and relevant fields of applications. No storage technic in its ideal conditions can be considered the best fit for all the applications, and each technic requires intense work to become acceptable for energy application.

Microwave radiation can be used to pre-damage hard rock to reduce the cost of drilling and excavation typically required in tunneling, mining, and deep Earth energy recovery. A 3D damage-based, electromagnetic-thermomechanical coupled model to simulate damage and fracturing of rock under microwave radiation is proposed in this manuscript. The model is first validated against experimental test and then used to simulate the damage and fracturing of rock under microwave radiation at various microwave power levels and radiation times. The simulations show that the distribution of temperature in the rock sample is extremely non-uniform, resulting in high thermal gradients that can damage and/or fracture the rock sample. Higher power levels and longer durations impart more damage. The simulations also show, under the same microwave radiation conditions, that the resultant sample temperature, and therefore damage, is higher in samples with high ratios of compressive to tensile strength. A good agreement between the modeling and experimental results suggests that the model can be used to assist in the management and optimization of mineral mining, oil and gas recovery, and deep Earth energy recovery.

Although mixing of proppants with the fracturing fluid can significantly improve the productivity of many unconventional gas reservoirs, application of this technique to coal seam gas reservoirs has been challenging. This is particularly due to the unique characteristics of coal, including its highly soft nature that promotes proppants damage mechanisms in coal. Therefore, correctly understanding the fracture conductivity of proppant supported fractures under coal seam gas reservoirs' conditions is essential in enhancing the coal seam gas (CSG) extraction. A series of advanced laboratory experiments combined with an X-ray CT analysis was thus conducted under in-situ reservoir stress conditions to understand the behaviour of two widely using proppants types in coal (sand, and ceramic proppants). According to the results, although sand proppants are more effective compared to stronger ceramic proppants at shallow depth-conditions, in-efficient at deeper depths, at which ceramic proppants are more effective. Importantly, the fracture width variation is strongly influenced by the shape of the proppants, where sand propped fractures can be subjected to a significant fracture width variation, even under a low confining stress condition available at a shallow depth due to the high angularity and associated particles edges' disintegration happens in the sand. At deeper depths (>6 MPa confinement), sand proppants are more vulnerable to being crushed under higher reservoir pressures, and ceramic proppants are more susceptible to embed into the coal surface. Overall, the study delivers a fundamental understanding of the proppant damage mechanisms in propped coal fractures under various types of proppants and their effect on the fracture flow, during the CSG production process. These findings would be essential benchmarks for the related future field applications.

CO2 interaction causes complex mechanical deformations and flow modifications in coal, depending on the spatial disposition of the fracture-matrix system. Sorption-induced matrix swelling reduces the local fracture aperture and correspondingly the fracture permeability, consequently influencing gas flow throughout the seam. Since these modifications are highly -heterogeneous and -localized, an explicitly-represented geometric model is essential for the accurate modelling of the fully-coupled process. In this study, the CO2 flow – coal deformation process is implemented in a numerical model at the scale of coal constituents (i.e. matrix blocks and cleats), through the inclusion of a spatially distributed 3D – discrete fracture matrix (DFM) network. Fracture geometry is generated from a stochastically simplified 2D fracture network obtained from micro-CT imaging. The approach is initially validated against experimental results from a single-fractured coal specimen and the analysis extended to the complex fracture geometry. The spatial and temporal evolutions of fracture/matrix pressure, adsorbed mass of CO2, adsorption-induced swelling, alterations in local fracture aperture and permeability, and contact modelling at fully fracture closure are specifically analysed with comparison against no-swelling behaviour. Results indicate that the high-permeability fracture pathways provide initial easy access for the CO2 to diffuse into the coal matrix, causing sorption-induced matrix swelling. Although the individual matrix blocks exhibit a slight shrinkage immediately upon injection of high fluid pressures within the fractures, sorption-induced swelling rapidly overcomes this, resulting in an overall volume expansion at full pressure equilibration. This is turn causes a significant reduction in fracture aperture and permeability. The magnitude of the local fracture aperture reduction depends on the swelling behaviour of the bounding matrix, that leads to essentially full-closure of small fractures, causing significant localized flow modifications to further CO2 injection in the vicinity of the particular fractures. The contact modelling approach identifies the timing and locations of fully-closing fractures in the complex geometry, where butt cleats exhibiting initial small apertures are prone to fully-close, compared to larger aperture face cleats that retain flow.

Near-wellbore screenouts during the shut-in stage due to the development of compact proppant clusters is an issue reported in several fracturing treatments for Coal Seam Gas (CSG) reservoirs. The usual solutions to counter this issue implemented in deep rocks such as Shale and Siltstone do not solve for coal reservoirs due to its geological characteristics. Therefore, the development of proppant packs is an expected outcome during CSG extraction, and the permeability in the proppant pack could decide the overall gas productivity. This study investigates the permeability of proppant packs prepared using the Under-compaction method to simulate compact proppant clusters experienced in near-wellbore screenouts. In this regard, two commonly used proppant types are selected; sand and ceramic, and a series of tri-axial permeability tests were conducted under various effective stresses relevant to CSG environments. According to the experimental outcomes, interestingly, both proppant packs exhibited non-Darcy and Darcy flow regimes, while the non-Darcy effect was more profound at low confining pressures due to its high packing porosity. Results showed that the permeability through the compact proppant pack depends on both the reservoir pressure and the type of proppants selected. The sand proppant pack (SPP) showed 1-2 orders higher than the permeability values of the ceramic proppant pack (CPP) until a threshold pressure is reached (10 MPa), after which the ceramic proppants produced higher permeability values. We also investigate the potential impact of the invasion of coal fines into the proppant packs and the corresponding pore blockings. The impact of fines invasion on CPP permeability was more potent compared to the fines induced SPP permeability. The shape of the ceramic particles, the polar effect of the alpha-Al2O3 atoms, and the attraction of the oxygen functional groups of the coal fines to these polar sites increase the likelihood of fines clogging in a ceramic proppant pack.

Commercial production of coal seam gas is a significant proportion of the total Worldwide natural gas supply due to its high gas storage capacity at shallow extraction depths. Coal seam gas recovery may be enhanced by pure fluid-based or proppant based hydraulic fracturing - the decision whether or not to use proppants depends on coal seam characteristics - in particular stress-permeability characteristics. Although proppant application has been common in deep reservoir fracturing, its application on soft rocks such as coal should be carefully investigated. Higher concentrations of proppant are known to minimise proppant damage in deep reservoirs, with stiffness and flow tortuosity also impacting the response. We explored the impact of proppant loading, coal type and fracture roughness on fluid flow characteristics in propped fractures by conducting a series of triaxial permeability experiments combined with micro-CT imaging. The results reveal that proppant application in coal is only effective for deep coal seam gas reservoirs with effective stress greater than 6 to 8 MPa (similar to 700 to similar to 900 m). Further, proppant application may cause up to 1-2 folds of fracture conductivity improvement in coal seam gas reservoirs located at over 1.2-1.4 km depths (effective stresses > 12 MPa). The impact caused by proppant embedment on fracture conductivity degradation is much significant compared to other proppant damage mechanisms. The effect, however, depends on the stiffness of the coal rock matrix and the proppant type implemented.

Steady-state and unsteady-state (downstream pressure build-up) gas permeability tests were conducted on low permeability siltstone at a series of upstream pressures during the loading and unloading processes. The characteristics of downstream pressure build-up curves are analysed in detail, and the permeability is calculated based on the data in the stabilization stage. Analysing approaches with and without consideration of the sample pore volume are used to obtain the unsteady-state permeability for both the real pressure and the pseudo pressure. Findings suggest that the permeability based on the pseudo pressure is generally lower than that based on the real pressure, with their ratio ranging from 0.75 to 0.98. The sample pore volume corrected permeability is 1.42–1.51 times of that without the consideration of sample pore volume. The apparent steady-state gas permeability is higher than the sample pore volume corrected permeability due to slip flow, while its intrinsic permeability is lower as the pore pressure is smaller in the steady-state test. The permeabilities decrease with the confining pressure in the loading path especially at lower confinements, while only part of the reductions is recovered during the unloading process. Increase of pore pressure enhances permeability under low confinement conditions. Water permeability is lower than gas permeability in steady-state test due to the water-rock interaction and the residual gas inside the sample.