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Fluid–shale interaction mechanisms and their implications on shale mechanical property evolutions are essential for both shale gas exploitation and CO2 sequestration. To understand the potential influence of water and CO2 exposure on shale, three shale samples from different formations were treated with dry supercritical CO2, supercritical CO2–water, and pure water for up to 30 days. Nanoindentation was used to measure the localized elastic modulus and hardness before and after fluid treatments. Combined nanoindentation with XRD–SEM–EDS analysis, we obtained the probing mechanical properties of three mineral phases in shales: quartz, organic matter, and mixed composites. The mechanical properties and creep behaviors of the mineral phases before and after fluid treatment were analyzed. XRD analysis and nanoindentation results reveal that the three shales are distinct in mineralogy and mechanical properties. The mechanical heterogeneity is related to the mineral constituents, which can be observed in the deconvolution results. The fluid treatment results indicate that dry supercritical CO2 does not impair the nanomechanical properties of shale, whereas water-contained fluid shows a significant weakening effect. The mechanical evolution of shale is both time-dependent and mineralogy-related. After supercritical CO2 and water treatment, the maximum deformations of three shales demonstrate an increasing trend, indicating a deterioration of the resistance to load. The elastic moduli and hardness of quartz, organic matter, and mixed composites exhibit apparent decreases after fluid treatment. The time-dependent mechanical behaviors of mineral phases were analyzed. CO2 and water play critical roles in the reactions with shale and the involved mineral reactions are discussed. The experimental findings provide insight into the nanomechanical property evolutions of shale in field operations involved in CO2 and water, such as fracturing and CO2 sequestration. Highlights: Shale mechanical property evolutions in fluid–shale interaction were traced on the nano-to-micron scale. Nanoindentation combined with XRD, SEM, and EDS was adopted to obtain the nanomechanical properties of mineral phases. The deformation of shales and creep behaviors of mineral phases were analyzed. The mechanical alteration after dry supercritical CO2 exposure was inapparent while significant when water exists. [ABSTRACT FROM AUTHOR]

Because of the existence of multiscale pores from nano- to macroscale, a multimechanistic shale gas flow process involving the Darcy and Knudsen flows occurs during gas shale well depletion. The respective contribution of the Darcy and Knudsen flows to the permeability is constantly changing with pressure evolution. In this study, laboratory measurements of shale permeability with CO2 injections were carried out under hydrostatic conditions, using the transient pulse-decay method. The "U"-shape permeability curve resulted in both positive and negative effective stress coefficients (Biot's coefficient) χ. A permeability turning point was thus created to partition permeability curves into the Darcy and Knudsen sections. The Knudsen effect was proven to be significant at low pressure/late time in the laboratory. Effective stress and sorption-induced deformation have been found to govern the Darcy permeability evolution under the tested experimental conditions. Thus, negative effective stress coefficients, together with the positive ones, should be applied to a nonmonotonic pressure-permeability evolution to explain the concurrent effect of the Darcy flow and Knudsen flow at different pore pressures. [ABSTRACT FROM AUTHOR]

Carbon dioxide-enhanced shale gas recovery (CO 2 -ESGR) has been identified as a promising technology for carbon emission mitigation as well as for its additional benefits regarding energy recovery. This review aims to consolidate comprehensive and contemporary findings concerning SC-CO 2 injection in shale formations. These findings indicate that CO 2 has a significantly greater adsorption capacity in shale than CH 4. Moreover, shale reservoirs possess the potential for large-scale carbon sequestration. Additionally, SC-CO 2 injection can lead to various CO 2 uptake-induced physicochemical reservoir rock alterations reflected by multimechanism–adsorption–dissolution–precipitation–transportation–wettability changes. This coupling mechanism can suppress the mechanical properties of shale, causing matrix swelling and crack sprouting, which in turn affects its storage capacity. • Advancements in the science and technology of CO 2 storage are presented. • Adsorption and chemical dissolution weaken the mechanical properties of shale. • The phase change of CO 2 and its interaction with rock triggered complex cracks. • The migration of CO 2 in reservoirs are needed to avoid potential leakage risks. [ABSTRACT FROM AUTHOR]

• The apparatus can effectively reduce the system and accumulated errors for shale sorption and diffusion measurements. • A high-accuracy differential pressure transducer offers an innovative perspective for quantifying adsorption of shales. • BET model is superior for high pressure sorption test with a better accuracy for five tested shales. • Gas diffusion coefficient of tested shale samples was found to be pressure-dependent. Accurate measurement of shale gas adsorption capacity is crucial for reservoir appraisal and production stimulation. Because of the limited adsorption capacity and finer pore size distribution in shale matrix, it is difficult to precisely quantify the adsorption capacity using traditional volumetric methods for coal adsorption measurement. An improved lab method for shale adsorption measurement and diffusivity evaluation was introduced by using a control group connected through a high accuracy differential pressure transducer. Isotherm curves of five shale samples from different basins were acquired using this system. For all shale samples, adsorption capacity for CO 2 is 2–3 times of that for CH 4. Adsorption isotherms for shale exhibited a better fitting trend with the BET model at the pressure range of lab scale, indicative of the quick decline at the diffusion-dominant region of reservoir production curve. It is found that the improved adsorption measurement method can effectively reduce the average accumulated error from 24.3%–11.3%, and it is qualified for measurement of materials with limited adsorption capacity. [ABSTRACT FROM AUTHOR]

Highlights • A new shale gas production model accommodating multi-mechanisms is established. • Inversion values of parameters match well the data from Barnett shale. • Production discrepancy increases with continuous depletion adding multimechanics. • Parameters have their own influence period and sensitivity intensity. Abstract Production decline analysis of multiple fractured horizontal wells (MFHW) is crucial for long-term shale gas development. Analytical solutions of production decline model accounting for sorption, diffusion (slip flow and Knudsen diffusion) and non-static (stress-dependent) permeability can precisely predict the long term production behavior, especially for the late time production period. However, little work has simultaneously incorporated all these mechanisms into production decline analysis for shale gas wells. In this work, a new production decline model for MFHW in shale gas reservoirs incorporating multiple flow mechanisms is established. To weaken the strong nonlinearities of seepage mathematical equation caused by combining multiple mechanisms, perturbation technology is employed to establish the point source solution considering stress-dependent permeability of MFHW and little effort has been done on this before. Besides, Laplace transformation, numerical discrete method, Stehfest numerical inversion algorithm and Gaussian elimination method are employed to solve the new model's mathematical problem. Estimated inversion values of reservoir parameters are consistent with the reported data from Barnett shale. Further, comparisons between production behaviors with and without multimechanics flows were made in three flow periods and the production discrepancy increases with continuous depletion, which is attributed that desorption and diffusion is increasingly important as pressure depleting. Finally, the effects of major parameters on production decline curves are analyzed by using the proposed model and it was found that different parameters have their own influence period and sensitivity intensity. [ABSTRACT FROM AUTHOR]

Gas transport in coal and shale matrices does not always fall into the continuum flow regime described by Darcy’s law. Rather, a considerable portion of this transport is sporadic and irregular when the mean free path of gas becomes comparable to the prevailing pore scale. A nonlinear process influenced by non-Darcy flow components like gas sorption, gas slippage, and diffusion occurs throughout gas recovery. Therefore, a new permeability model with pressure-dependent weighting factors is presented to describe gas flow. This model contains the coupling of matrix flow with explaining the impact of both multiple flow regimes and stress-strain relationship on unconventional gas permeability evolution. The stress-strain relationships were derived from thermal-elastic equations and can be incorporated into the fracture-based flow component, enabling permeability prediction under uniaxial strain and hydrostatic conditions. The “U-shape” permeability trends caused by flow dynamics and geomechanical effects are observed in modeling results, which match experimental data. The agreement between modeling results and experimental data shows that gas permeability can be fully characterized by the presented model. This model has the ability to predict uniaxial strain permeability to hydrostatic permeability in a laboratory scale. [ABSTRACT FROM AUTHOR]

The Lower Cambrian Niutitang and Lower Silurian Longmaxi shales in the Middle‐Upper Yangtze area are considered the primary shale gas units targeted for development in China. To shed some light on the difference in nanopore structures between Niutitang and Longmaxi shales, systematic comparative investigations were conducted using various techniques, including geochemical analyses, field emission scanning electron microscopy (FE‐SEM), high‐pressure mercury intrusion porosimetry (MIP), and low‐pressure N2/CO2 adsorption techniques. The results show that both Niutitang and Longmaxi shales have high total organic carbon (TOC) content and complex mineral compositions. The porosity of Longmaxi shales is higher than that of Niutitang shales, with an average value of 3.26% and 2.04%, respectively. Interestingly, for both shale formations, the mesopores (2–50 nm) are the major contributors to pore volumes, whereas the specific surface area is dominated by micropores (<2 nm). For the mesopore size distributions (PSDs) calculated from the N2 adsorption, the Longmaxi shales have a dominant pore size ranging from 10 to 60 nm. In contrast, there are more fine mesopores (2–8 nm) in the Niutitang shales. Furthermore, we found that numerous nanoscale pores are well‐developed within graptolite‐derived organic matter (OM) in the Longmaxi shales. These interconnected graptolite periderm pore systems may not only provide a storage space for both adsorbed and free gas but also serve as pathways for gas transport. The Niutitang shales developed relatively fewer OM pores with smaller diameters, lower OM surface porosity, and lower connectivity compared to the Longmaxi shales. The differences in OM pore structure partly explain why there is a large production difference between these two formations. [ABSTRACT FROM AUTHOR]

Lacustrine shale gas has received considerable attention and has been playing an important role in unconventional natural gas production in China. In this study, multiple techniques, including total organic carbon (TOC) analysis, X-ray diffraction (XRD) analysis, field emission scanning electron microscopy (FE-SEM), helium pycnometry and low-pressure adsorption have been applied to characterize the pore structure of lacustrine shale of Upper Triassic Yanchang Formation from the Ordos Basin. The results show that organic matter (OM) pores are the most important type dominating the pore system, while interparticle (interP) pores, intraparticle (intraP) and microfractures are also usually observed between or within different minerals. The shapes of OM pores are less complex compared with the other two pore types based on the Image-Pro Plus software analysis. In addition, the specific surface area ranges from to and the pore volume varies between and . Two fractal dimensions and were calculated using Frenkel-Halsey-Hill (FHH) method, with varying between 2.510 and 2.632, and varying between 2.617 and 2.814. Further investigation indicates that the fractal dimensions exhibit positive correlations with TOC contents, whereas there is no definite relationship observed between fractal dimensions and clay minerals. Meanwhile, the fractal dimensions increase with the increase in specific surface area, and is negatively correlated with the pore size. [ABSTRACT FROM AUTHOR]

Magmatism can significantly alter the pore structure of shale formation due to the thermal and pressure effects, thus the gas enrichment mechanism is naturally affected. The uncertainty of shale gas development has been raised in the petrogeology community due to the magma intrusion. This study investigates pore evolution, pore alteration, and gas enrichment of gas shale in the Permian Gufeng Formation (Fm.) in the Lower Yangtze, Liqiao district. In this work, multiple techniques were used for shale characterization including total organic carbon (TOC) content quantification, reflectivity microscope tests, X-ray diffraction, high-pressure mercury injection, low-pressure nitrogen adsorption, and carbon dioxide adsorption measurements. The results show that the closer the shale approaches the intrusion, the higher the vitrinite reflectance (R o) and quartz content, the lower the TOC and clay mineral content, and metamorphic minerals for instance augite and anatase appear in the affected shale formation. As shale is closer to the intrusion, the type of pores changes from small pores (10～100 nm) to super-large pores (1000～100,000 nm), and the super-small pores (6～10 nm) almost disappeared. In addition, a decrease in the fractal dimension of the pores was observed indicating that the heterogeneity and complexity of the pore structure are reduced. Within the contact metamorphism halo, the maximum adsorption capacity, pore volume, and specific surface area decrease with increasing proximity to the intrusion, which reduces the potential for shale gas enrichment. In basin-scale, a huge contact metamorphic range and plugging effect of the intrusion in sill intrusion generate enormous amounts of hydrocarbon and block the escape of the shale gas. Due to these factors, the intrusion can be conducive for shale gas enrichment. However, the dike that penetrates the shale reservoir is not conductive to shale gas enrichment because the fracture channels created in the contact metamorphism halo accelerate the escape of the shale gas. This study proposed critical theories of shale gas enrichment and could increase the success rate of shale gas exploration. • Magmatism heavily impact on pore of shale reservoir in the Lower Yangtze region. • The magmatism has a prominent effect on geomaterials and pore evolution. • Contact metamorphism halo is unfavorable for the enrichment of shale gas. • The gas enrichment of three invasion patterns are different on the basin scale. [ABSTRACT FROM AUTHOR]

There is a growing body of evidence that gas situated within the pores of nanoporous materials may not have the same equation of state (pressure, volume, and temperature, PVT) properties as macroscopic free gas. However, there is limited experimental measurement of in-situ fluid properties for gases taken up by nanoporous shales. In this work, we use a gas injection porosimetry approach to measure the gas storage capacity of four different North American shales (Bakken, Marcellus, Haynesville, and Mancos) and in-situ gas density for a few different hydrocarbon and noble gases. We find the porosity measured with helium to be reasonable between 5% and 16.4%. However, when using other gases such as methane, argon, and ethylene, the equivalent porosity estimations are extremely high, with the highest measured value being 309% for ethylene gas in a Marcellus shale sample. Such extreme results raise questions on the validity of the underlying assumptions of the porosimetry equations, in particular, the description of gas density within shale nanopores with macroscopic density. The experimentally measured density of in-situ gas is found to be up to 28 times higher than the theoretically estimated one at the equilibrium PVT conditions. This in-situ densification of gas is independently verified using X-ray CT imaging on one of the samples – the Marcellus. The underlying mechanism for gas densification could be explained by adsorption, in which case the proportion of adsorbed gas is estimated to be between 12% and 96% for the various gas-sample pairs. Surface area measurements show that a monolayer of adsorbed gas can only account for 27%–42% of the adsorbed gas. This calls into question the commonly assumed Langmuir monolayer model of adsorption, and indicates that gas densification within shale nanopores can be attributed to a multilayer adsorption mechanism and/or other unidentified mechanisms that require further study. • PVT properties of single-component gas confined in nanopores differ from free gas. • CH 4 , Ar, C 2 H 4 , and Xe gases become denser after injection into nanoporous shales. • Measured in-situ gas densities between 110% and 2850% of free gas density. • Adsorbed gas may account for 12%–96% of total in-situ gas storage. • Langmuir adsorption can only account for 27%–42% of the measured adsorbed gas. [ABSTRACT FROM AUTHOR]

Gas transport in the shale matrix is controlled by pore structure, which can ultimately influence natural gas production potential and carbon sequestration in shale gas reservoirs. In this study, in situ small-angle neutron scattering (SANS) measurements under methane and CO 2 injections were employed to investigate two Marcellus Shale thin section samples cut parallel and perpendicular to the bedding. Marcellus Shale nanopores show intrinsic anisotropy over the detected length scale of 5–2000 Å. Microscopic gas transport could be inhibited due to the decrease of accessible porosity with increasing gas pressure. The degree of inhibition may be higher for CO 2 than for methane, and for the direction normal to the bedding than in the bedding direction. In addition, under the condition of liquid CO 2 , higher porosity reduction for the direction normal to the bedding may insight into nanoscale anisotropic wettability in the shale matrix. • In situ SANS is used to analyze the anisotropic pore structure of Marcellus Shale. • Porosity and surface area in the bedding direction are higher than those normal to the bedding. • Accessible porosity and surface area decrease with increasing gas pressure in both directions. • CO 2 has a higher effect on porosity reduction than methane. • Irreversible damage of pore structure is found in both bedding and normal directions. [ABSTRACT FROM AUTHOR]

Shale matrix pore structure controls the gas storage mechanism and gas transport behaviors. We employed various techniques to characterize the complex pore structures of 12 shale samples collected from two marine shale formations in upper Yangtze area (UYA) in China. The characterization techniques include field emission scanning electron microscopy (FE-SEM), high-pressure mercury intrusion porosimetry (MIP), and low-pressure N 2 /CO 2 adsorption. The excess methane adsorption capacity was measured for each sample and the results were modeled using Langmuir model. Based on the FE-SEM image analyses, micro- and meso-pores within organic matter and inter-particle pores between or within clay minerals are the most commonly developed in these shale samples. Both uni- and multi-modal pore size distributions (PSDs) were observed, and a significant portion of pores are in the pore size range between 3 and 100 nm. It was also found that the micropore (<2 nm) is the major contributor to the overall specific surface area (SSA), whereas most of the pore volume is occupied by mesopores (2–50 nm). Two different fractal dimensions, pore surface fractal dimension ( D 1 ) and spatial geometry fractal dimension ( D 2 ), were estimated from low pressure N 2 isotherms, with D 1 ranging between 2.469 and 2.682, and D 2 ranging between 2.576 and 2.863, indicating that the surface and volume of pore structure are heterogeneous. Samples with higher D 1 can provide more adsorption sites for methane and tends to have relatively high adsorption capacity, whereas shales with higher D 2 do not influence the gas adsorption and storage capacities. Methane adsorption capacity increases with the increase of both micropore volume and micropore surface area, and this confirms that microporosity is the governing factor on methane adsorption capacity and storage. [ABSTRACT FROM AUTHOR]

Understanding methane sorption behavior in the gas-shale system is of great importance for evaluating reservoir production potential and reducing exploration risk. In this study, methane sorption capacities of total 12 organic-rich marine shale samples from the southwest of China were measured by volumetric method. The absolute sorption results were modeled using Langmuir, Brunauer–Emmett–Teller (BET), Dubinin–Radushkevich (D–R) and Dubinin–Astakhov (D–A) models. The accuracy of each model for quantifying shale gas sorption capacity was analyzed and compared by using a residual error analysis technique. The impacts of organic and inorganic constituents on the methane sorption capacity were also analyzed. The experimental results indicate that the maximum absolute methane sorption capacity of the collected marine shale samples is between 0.50 cm 3 /g and 3.41 cm 3 /g, which positively correlates with the total organic carbon (TOC) content. The TOC-normalized methane sorption capacity shows a positive correlation with the total clay mineral content and exhibits a significant increase with increasing illite–montmorillonite mixed layers content when it is greater than 9%. For the results of gas sorption modeling, the D–A model is superior to the Langmuir, D–R and BET models, because of the additional parameter describing the micro-heterogeneity of shale rocks. The most commonly used Langmuir model gives a reasonable fit for most of the shale samples, which is comparable to D–A modeling results when TOC content is greater than 5%. The BET model performs poorly and thus it is not recommended for methane–shale sorption modeling exercise. Therefore, both D–A and Langmuir models are recommended for describing methane adsorption on organic-rich shale samples. [ABSTRACT FROM AUTHOR]

Gas desorption laws varies with coal particle size. Their proper description is of great importance to natural gas engineering. This paper tries to summarize the internal links in commonly used models and combine them into a more general form. The combined general model is capable of describing fracture flow, matrix diffusion and surface sorption processes in pores with shapes like flat plates, cylinders and spheres. It can also be simplified into a power function which can be readily implemented into simulation of sorption and calculation of dynamic Fickian diffusion coefficients. Experiments including low-temperature liquid N 2 adsorption, proximate analysis, isothermal methane sorption and desorption experiments with different particle sizes were conducted to validate the model. Other sorption data from literature were also collected for validation. The fitting results can help explain the size dependence of desorption characteristics and show the flow type evolutions during the damage of pore system. Unlabelled Image • Summarize internal links between commonly used gas transport models in coal. • Propose a model that can describe multi gas transport in multi shape pores. • Obtain controlling transport pattern in different gas desorption curves. [ABSTRACT FROM AUTHOR]