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Both mudstone and gypsum caprocks play a vital role in the accumulation and preservation of petroleum because of their low porosity and permeability. The transport property of caprocks changes due to the tectonic compression or uplift. The permeability evolution behavior may differ significantly between the two caprocks, however, they are not well-understood. Therefore, in this work, mudstone and gypsum samples were collected and a series of experiments were performed to investigate the permeability evolution at different stress conditions. The results show that the permeability of the original gypsum sample is one to two orders of magnitude lower than that of the original mudstone due to different texture of the rocks. The mudstone has bedding and clastic texture while the gypsum is crystalized. The permeability evolution in triaxial compression test after the sample failure increases up to two orders of magnitude for mudstone, while the permeability for gypsum does not increase and the final permeability is even lower than the initial permeability. Permeability evolution under unloading confining stress tests shows that it increases up to three orders of magnitude for mudstone and about one to two orders of magnitude for gypsum. The differences are mainly due to the different failure modes, brittle deformation for mudstone and ductile deformation for gypsum. Moreover, the generated fractures cross the mudstone samples while the generated shear bands do not cross the gypsum samples. A model was developed to describe the permeability behavior for both loading and unloading processes based on the change of volumetric strain. • The permeability evolution of the original gypsum and mudstone samples are studied. • The permeability for triaxial compression test for mudstone increases dramatically, but not for gypsum. • Permeability during unloading increases three orders of magnitude for mudstone and one to two orders of magnitude for gypsum. • A model is developed to describe the permeability behaviors for both mudstone and gypsum. [ABSTRACT FROM AUTHOR]

Microwave heating may be used to stimulate fracture formation and the release of hydrocarbons in gas shales. Although extensively studied experimentally and numerically, the microscopic observations are not fully explained in current work where the heating, at sample-scale, and fracturing, at the mineral-scale, are represented independently. Furthermore, the geometry, structure and mechanical interaction of different minerals are not fully considered in current approaches. We present a novel simulation approach to investigate the coupled electromagnetic-heating-stress-damage process. Microwave heating is simulated at sample-scale and the resulting stress-damage response is examined at micro-scale where minerals with contrasting thermo-mechanical characteristics are stacked as lamellae, instead of nested internally as in previous representations. A three-stage temperature evolution profile is observed in the shale samples – although some stages may be absent in other rocks. The mathematical model accounts for the three modes of stress generated between minerals: horizontal stress ( σ h ) (tensile stress parallel to the grain-grain interface) and the normal stress( σ n ) (tensile stress normal to the grain-grain interface) applied on the minerals, and the shear stress ( τ ) applied on the interface between different minerals. The minerals comprising the shale matrix are categorized into three types – 'high', 'intermediate' and 'low' – conversion efficiency based on their susceptibility to thermal stressing from microwave irradiation. Shear damage and intergranular fracture usually occurs for minerals with high dielectric permittivity. Transgranular fracture may feature both in high permittivity minerals, due to the larger induced horizontal stress ( σ h ), and in low permittivity minerals - due to high volume fraction and larger size. The simulation approach is a powerful way to link the macro-scale characterization and heating to micro-mechanisms of rock failure. Also this work provides mineral classification and criteria to define a priori evaluation of the effectiveness of microwave treatment of shales and other mineral aggregates. [ABSTRACT FROM AUTHOR]

The sample size or particle size of shale plays a significant role in the characterization of pores by various techniques. To systematically investigate the influence of particle size on pore characteristics and the optimum sample size for different methods, we conducted complementary tests on two overmature marine shale samples with different sample sizes. The tests included small-angle neutron scattering (SANS), gas (N2, CO2, and H2O) adsorption, mercury injection capillary pressure (MICP), and field emission-scanning electron microscopy (FE-SEM) imaging. The results indicate that artificial pores and fractures may occur on the surface or interior of the particles during the pulverization process, and some isolated pores may be exposed to the particle surface or connected by new fractures, thus improving the pore connectivity of the shale. By comparing the results of different approaches, we established a hypothetical model to analyze how the crushing process affects the pore structure of overmature shales. Our results imply that intact wafers with a thickness of 0.15–0.5 mm and cubic samples (~1 cm3) are optimal for performing SANS and MICP analyses. Meanwhile, the 35–80 mesh particle size fraction provides reliable data for various gas physisorption tests in overmature shale. Due to the intrinsic heterogeneity of shale, future research on pore characteristics in shales needs a multidisciplinary approach to obtain a more comprehensive, larger scale, and more reliable understanding. [ABSTRACT FROM AUTHOR]

Brittleness is an essential parameter in the evaluation of wellbore stability and hydraulic fracturing design of shale reservoirs. It is an inherent geomechanical property controlled by the mineral composition, sedimentary structure, and geological condition. However, traditional brittleness evaluation methods based on the elastic parameters and mineral composition analyses are limited by the anisotropic petrophysical behaviors of continental organic-rich shale. In this paper, we analyzed the contributing mechanical properties of individual mineral components and organic contents of shale using laboratory stress experiments. Based on the principle of energy conservation and post-peak deformation, we evaluated the brittleness and analyzed the main factors influencing shale brittleness. In addition, we established a new method of quantifying the representative shale Brittle-Ductile Index (BDI) via combined consideration of its organic matter content, mineral composition, and mechanics characteristics. The results identified quartz and feldspar as the main brittle minerals with a substantial contribution to shale brittleness. Conversely, the organic matter and carbonate minerals have little effects on the pre-peak elastic parameters but are very sensitive to the post-peak rupture parameters and significantly influence the brittle shale fractures. Specifically, the calculated BDI is high in areas of rich in organic matter or developments of shale lamination. This usually leads to brittle fracturing along the weak surfaces when the stress is mainly applied in the bedding directions. In contrast, the BDI is small in carbonate rich shales as mineral particles are heavily compacted which disperses the stress, resulting in scattered ductile fractures. • Three groups of shales with different TOC and mineral contents were investigated. • Pre- and Post-peak deformation behaviors have completely different effects on rock fractures. • New shale BDI indicates that the bedding is the key controlling factor for deformation mechanisms. [ABSTRACT FROM AUTHOR]

Mineralogical and geochemical characteristics of coals provide crucial information on their potential clean, efficient, and integrated utilization. In this paper, the mineralogical and geochemical behaviors of the No. 5 coals of the Taiyuan Formation in the Weibei Coalfield, North China, were investigated, and their geological controlling factors were subsequently discussed. The minerals in the Weibei coals mainly consist of kaolinite (8.3%), calcite (5.0%), and pyrite (3.1%), with minor proportions of tobelite (2.9%), dolomite (1.7%), quartz (1.8%), and traces of siderite (0.4%) and gypsum (0.6%). Several critical elements, including Nb (19.8 mg/kg), Ta (3.6 mg/kg), Zr (71.0 mg/kg) and Li (32.3 mg/kg), occur at concentrations higher than those averages for world hard coals, making the Weibei coals potential sources of these critical elements. Several factors, terrigenous material, seawater invasion, and hydrothermal fluids are responsible for these mineralogical and geochemical characteristics. The L-type rare earth elements and yttrium (REE-Y) enrichment in the roofs and partings, Al2O3-TiO2 and Zr/TiO2-Nb/Y plots, and negative Eu and weak negative Ce anomalies in the Weibei coals indicate a felsic-intermediate dominated sediment provenance primarily derived from the Qilian-Qinling Oldland on the South. Marine bioclastic limestone, negative Ce and positive Y anomalies in coals imply the influence of seawater on the Weibei coals. Last but not least, the cleat-infilling and/or fracture-infilling calcite, pyrite, barite, and tobelite as well as the positive Eu and Gd anomalies, H-type, and M-type REE-Y enrichment patterns suggest the influence of hydrothermal fluids, which lead to re-distribution of some critical elements from roof and parting to the underlying coal seam. [ABSTRACT FROM AUTHOR]

One of the biggest challenges in evaluating the transport and storage properties of shales is understanding how the pore structure and network evolve in the same stratigraphic shale during catagenesis. Using a combination of CO 2 adsorption, mercury intrusion porosimetry, as well as scanning electron microscopy, we have described the evolution and the abrupt changes (jump) of pore characteristics in lacustrine shale at oil and gas maturation. With an increase maturity, our sample set exhibited abrupt changes in porosity-related characteristics. Porosity and surface areas presented a decline and then an increase, and a jump occurred due to hydrocarbon generation, with the minimum value in late maturity (i.e. vitrinite reflectance of ~1.3%). These changes were accompanied by corresponding changes in pore-size distributions, surface area percentage, and multi-scale pores volumes. The trends in porosity variation were related to different organic matter and mineral contents in our samples, to some extent, with the degree of maturation being the dominant influence. We found that inorganic pores were the main contributor to the porosity of less mature shales, while porosity in gas-mature shales was dominated by organic matter pores. In this work, we showed that organic matter transformation was a centric component of pore evolution. Our findings may fill significant gaps in understanding and predicting pore development, with respect to the maturity of lacustrine shales. • Pore volume and surface area in lacustrine shales show jumps with maturity. • The porosity of oil- and gas- mature shales is governed by mineral interparticle pores and OM-hosted pores, respectively. • From oil-window to gas-window, porosity-related characteristics present a decline and then an abrupt increase. [ABSTRACT FROM AUTHOR]

• The competitive adsorption behaviors of CO 2 and CH 4 in coal are revealed. • Variation in stress–strain are analyzed under different pressure conditions. • The bulk strain caused by CO 2 adsorption is higher than that caused by CH 4. • Under the same declines in pressure, the desorption of CH 4 is greater. • Permeability decreases and then increases with increasing pore pressure. The injection of CO 2 into deep coal seams can improve the recovery of CH 4 and contribute to the geological sequestration of CO 2. To reveal the controlling factors associated with CO 2 displacing CH 4 , experiments were conducted to simulate the process under different confining pressures (8, 12, 16, and 20 MPa) and CO 2 injection pressures (1–6 MPa). The results show that coal can adsorb more CO 2 than CH 4. However, the permeability of CH 4 is greater than that of CO 2 under inlet gas pressures of 1–5 MPa. For CH 4 saturated coals, the CH 4 desorption volume is higher under CO 2 displacing conditions compared to pure CH 4 desorption processes under the same pressures. The coal adsorbed CO 2 decreases under high pore and confining pressures, indicating the displacement results may be better in shallow buried coals. The axial, radial, and bulk strains of coal show steady, sharp, and then slow declining trends with decreasing pore pressures, and the inflection points generally occur at 5.25 and 3.25 MPa. Meanwhile, the strain in three directions decreases exponentially with the increase of effective stress, and the radial strain is higher than the axial strain under each confining pressure. With the combined influences of effective stress, matrix swelling/shrinkage, and gas slippage, the permeability decreases first and then increases with the decrease of pore pressure. With the decrease of pore pressure and the increase of confining pressure, the combined influence of the three factors on coal permeability gradually weakens. The results would be beneficial for controlling the injection process and permeability variation predicting during CO 2 sequestration and the replacement of CH 4 in coals at different burial depths. [ABSTRACT FROM AUTHOR]

Stimulation of microbial methanogenesis on intact coal under in-situ conditions is demonstrated in a series of 18 anaerobic core flooding experiments. The experiments used core samples from producing coalbed methane fields in the Surat Basin and Bowen Basin, with formation water containing methanogenic microbial consortia sourced from within the matching basin. The formation water was amended with nutrients containing phosphorus and nitrogen before being used in core flooding experiments of between 6 and 20 weeks duration. Since the core floods used degassed coal core at reservoir pressure, gas generated during the core flood could be adsorbed and retained by the coal. Therefore the quantity of methane generated was determined at the end of the experiment by decreasing the pore pressure and measurement of the volume of gas desorbed from the core sample. The amount of methane generated, averaged on a per week basis, varied considerably across the different core floods but was up to 7.75 μmol methane per gram of coal per week, comparable to previous studies where biostimulation experiments were conducted on crushed coal particles. During the core floods, the nutrient concentration was measured periodically in inflow and outflow water samples and the rates of nutrient consumption determined. The concentration of methane dissolved in the water samples was also determined and used as an indicator during a core flood of the relative rate of methanogenesis. Plateaus in gas generation were observed in the majority of core floods despite constant nutrient supply, indicating nutrient availability is not the single limiting factor to sustained methanogenesis. Higher gas generating core floods displayed higher rates of utilisation of phosphorus, underlining its importance in stimulation of microbial activity, while nutrient utilisation and gas generation measured in the absence of continuous nutrient delivery suggests the possibility of injection and production from a single CBM well. Results demonstrate the ability to stimulate gas generation on intact coal under reservoir conditions, an important step in development of technology for increasing gas content in depleted or undersaturated CBM fields. • Biostimulation demonstrated on intact coal at reservoir pressure and temperature. • Core flooding CH 4 generation rates compare to studies utilising crushed coal. • Methane generation rates plateau in the presence of consistent nutrient supply. • Nutrient uptake did not provide quantitative prediction of total gas generation. • Nutrient utilisation and gas generation observed during formation water shut-in. [ABSTRACT FROM AUTHOR]

The Fushan sag is an important petroleum-bearing unit in the Beibuwan Basin, South China Sea. However, genetic relationship between oil and source rocks has not been well understood. In this work, 43 mudstone samples and 22 crude oil samples in the sag were collected for molecular geochemical and isotopic analyses to investigate this relationship. The geochemical data shows that the mudstones in Liushagang formation have poor to good oil generation potential with TOC ranging from 0.45 to 2.19 wt% and the kerogen is mainly type Ⅱ. Two types of crude oils were identified in this study. The first type of Group A oils including the subgroup A 1 and subgroup A 2 has the characteristics of low maturity with low saturated hydrocarbon content and lighter δ13C values in the Huachang uplift. The source rocks for the Group A oils were deposited under suboxic to oxic and freshwater environment containing more terrestrial higher plant and less angiosperm. The subgroup A 1 oils in Els 1 1 reservoirs are separated from subgroup A 2 in the Els 1 2 reservoirs by relatively lower maturity. The subgroup A 1 and subgroup A 2 oils are closely related to the Els1 to Els 2 1 and Els 1 2 to Els 2 1 source rocks, respectively. While the second type of oils including Group B and Group C oils has higher level of maturity with higher saturated hydrocarbon content and heavier δ13C values. The source rocks of Group B oils were deposited in a freshwater environment with lower salinity, and more angiosperms and terrestrial higher plants input than those of Group C oils. Two subgroups are divided in the Group B oils, of which subgroup B 1 oils have higher maturity and their source rocks were deposited in lower salinity with more terrestrial higher plant input than that of subgroup B 2 oils. The subgroup B 1 oils occurring in the Els 3 1 reservoirs from the Huachang uplift are likely related to Els 3 1 source rocks, while subgroup B 2 oils in the Els 2 2 reservoirs from the southern slope area of the Bailian subsag is linked with mixed source of Els 2 2 and Els 3 1 mudstones. The Group C oils are distributed in Els 2 2 and Els 3 1 reservoirs in the Huachang uplift and their oil source are from Els 3 2 mudstones. Two petroleum plays are likely divided by the mfs in Els2 based on the oil-source correlation in the sag. Group B and Group C oils belong to the lower play, and Group A oils only occur in the upper play. The distribution and accumulation of different groups of oils are mainly controlled by the special two-layered tectonostratigraphic framework and the transport ability of fault zone in the sag. This study clarifies the types of oils, as well as the oil-source correlation and the spatial distribution of different groups of oils. The results could benefit the further petroleum exploration and resource evaluation in the sag. • The characteristic and maturity of source rock in the different members is presented. • Two types of crude oil are divided based on carbon isotope and molecular composition. • The oil-source correlation of different oil families is addressed. • Two petroleum plays and the mechanism of migration and accumulation are proposed. [ABSTRACT FROM AUTHOR]

An evaluation of shale pore connectivity is essential for predicting the production behavior and optimizing the development plan of shale gas. To systematically investigate the multiscale connectivity characteristics and controlling factors, complementary tests were conducted on four overmature marine shale samples from southern China (one each from Longmaxi Formation and Wufeng Formation, and two from Niutitang Formation) with different maturity and composition. The methods included mercury intrusion capillary pressure (MICP), spontaneous imbibition with deionized water and n-decane, saturated diffusion distribution with seven nano-sized tracers, N 2 physisorption, small-angle neutron scattering (SANS), and focused ion beam-scanning electron microscopy (FIB-SEM) tomography. Moreover, a novel repeated MICP measurement technique was developed and used to evaluate the pore connectivity from the distribution behavior of residual mercury. Results indicate that the connectivity loss of hydrophilic pore networks owing to an increased maturity and the compaction causes pore shrinkage and bond breakage between pore networks. According to the three-dimensional reconstruction and pore network extraction of FIB-SEM images, pores in organic matter (OM) have a good pore connectivity, but the minerals surrounding the OM reduce the overall pore connectivity of the shale matrix. By evaluating the pore connectivity using different methods, the hydrocarbon migration pattern in overmature marine shales was established. Our results imply that in addition to creating induced fracture networks, effectively connecting induced fractures with preexisting microcracks or joint sets between OM pore networks and transport pores can also be used to enhance overall pore connectivity. Microwave heating in shale reservoirs may be an effective way of further improving the production and recovery of hydrocarbons. • Pore connectivity for shale samples from marine formations was studied with complementary methods at multiple scales. • A novel repeated MICP measurement was developed to evaluate the pore connectivity. • Shale pore connectivity was indicated from diffusion distribution of seven nanotracers. • Controlling factors of pore connectivity were discussed by visual and quantitative techniques. • Hydrocarbon migration pattern was established based on pore connectivity of shale. [ABSTRACT FROM AUTHOR]

Nuclear magnetic resonance (NMR) has been applied widely and successfully in conventional and unconventional reservoirs, and can be used to investigate petrophysical properties and fluid flow characteristics. This non-destructive, sensitive, and quick technique has been utilized in determination of pore type, porosity, pore size distribution, permeability prediction, wettability estimation, and fluid type, state and flow behavior. In this paper, the application of NMR to investigate coalbed methane and shale reservoirs is reviewed. Most of the reviewed studies are related to porosity and pore characteristics, which can be determined by analyzing the characteristics of the T 2 distribution, allowing for examination of pore type and pore connectivity as well as calculation of total porosity and pore size distribution. Permeability models developed for reservoir rocks and based on porosity determined using NMR are well established and have been extended or modified to evaluate the permeability of coal or shale. Reviewed studies also include wettability investigation by comparing the subtraction of T 2 distribution before and after fluid injection. Reviewed recent advances have further discussed the method of distinguishing fluid type, fluid state, and simulating fluid behavior using one-dimensional and two-dimensional NMR methods combined with changes of T 2 distribution. The aim of this review is to provide readers with an overview of the capabilities of NMR and its extension to scientific research by improving the parameter optimization of the instrument and establishing the calculation method for effective surface relaxivity for coals or shales. • Conclusion of nuclear magnetic resonance (NMR) measurement and theory • Pore type, porosity, pore size distribution of coal and shale by NMR T 2 distributions • Permeability prediction models and wettability estimation based on NMR • Distinguishing fluid type, state by using one-dimensional and two-dimensional NMR methods • Simulating fluid behavior according to the changes of T 2 distributions [ABSTRACT FROM AUTHOR]

• Permeability tests were performed on fractured shale with high confining pressure. • The permeability of the fractured samples decreases sharply with effective stress. • A stress-dependent fracture permeability model was derived and validated. • Shale fracture compressibility is strongly stress dependent. It is of great importance to investigate the change in the permeability of stimulated shale gas reservoirs under high effective stress because the depths of producing shale gas reservoirs in China have gradually exceeded 3500 m. In this study, a series of permeability measurements were performed on two fractured Longmaxi shale samples under confining pressures from 5 to 80 MPa. Experimental results show that the measured apparent permeability of the fractured samples sharply decreases with effective stress. The intrinsic permeability of fractured shale decreases with increasing effective stress, and the Klinkenberg constant is almost invariable. Then, a stress-dependent fracture permeability model was derived based on the fracture compressibility models. The modeling results indicate that the permeability model derived in this study can accurately describe the experimental data, with errors of 5.63% and 2.24% for samples I and II, respectively. A comparison of the modeling results using this model to those using permeability models available in the literature indicates that the model derived in this study is preferable, especially for a broad effective stress range. Moreover, the average compressibility of fractured Longmaxi shale decreases from 0.077 to 0.014 MPa−1 with effective stress increasing from 4.13 to 79.65 MPa, showing that fracture compressibility is strongly stress-dependent. The results in this paper will be important for the prediction of permeability change and gas production behavior for the development of deep shale gas. [ABSTRACT FROM AUTHOR]

The simplified local density (SLD) model has been frequently utilized to describe gas adsorption in porous media. The common assumptions associated with the SLD model are the graphene slit and uniform distribution of atoms. However, these fail to depict the heterogeneous surface of minerals. In this study, the original SLD model was modified by substituting mineral crystal structures for the homogeneous carbon layer when building the slit. The modified model may capture the heterogeneity-induced variation of the fluid-pore interaction potential and adsorbed phase density near the mineral surface. The calculated adsorption isotherms of methane and carbon dioxide on illite and calcite surfaces at 330.15 K were compared with literature experiment data to validate the modified SLD model. For the simulation of gas adsorption isotherms, the modified model predictions agree reasonably well with the previously reported experiment results using the gravimetric method. The calculated density profile in the slit indicates the monolayer adsorption behavior of CH 4 and CO 2 . Based on more precise interaction potentials, the number of regression parameters was reduced to two, and the physical meaning of the model parameters was clarified. Therefore, for estimating hydrocarbon storage in reservoirs, the modified SLD model could be used as an efficient alternative to time-consuming molecular simulation methods.

To reveal how mineral changes affect a coal pore structure in the presence of water, an autoclave was used to carry out the supercritical CO 2 (ScCO 2 )-H 2 O-coal interaction process. To reveal the changes in pore complexity, mercury intrusion capillary pressure (MICP), low-pressure nitrogen adsorption, CO 2 adsorption, and field emission scanning electron microscopy (FESEM) experiments were combined with fractal theory. The experimental data of MICP show that the MICP data are meaningful only for the pore fractal dimension with pore sizes >150 nm. Therefore, the pores were classified into the classes >150, 2-150, and <2 nm. The results show that the pore volume and specific surface area of the coal increased significantly after the reaction. ScCO 2 -H 2 O can cause the formation of many new pores and fractures in the coal. The presence of H 2 O may increase the potential for the injection of CO 2 into the coal seam. The complete dissolution of calcite surfaces caused a significant increase in the pore volume and specific surface area of the pores >150 nm. The morphologies of these pores are controlled by the morphologies of the complete dissolution carbonate particles. The pore morphologies were relatively uniform, and the fractal dimensions decreased. However, the incomplete dissolution of calcite leads to irregular variations in the morphologies for the pores in the 2-150 nm pore size range. The pore morphologies that are produced by incompletely dissolved calcite particles are more complex, which increases the fractal dimensions after the reaction. The fractal dimensions of the pores <2 nm decreased after the reaction, indicating that the newly generated micropores were more uniform and had regular pore morphologies., Competing Interests: The authors declare no competing financial interest., (© 2023 The Authors. Published by American Chemical Society.)

Shale gas has become an important natural gas resource in recent years as the conventional oil and gas resources are depleting. Shale gas content is one of the most important parameters for reserve calculation and sweet-spot prediction. The traditional core recovery method is widely used to determine gas content. However, the estimation of lost gas content is the main factor of error and difficulty. Large errors and uncertainties occur when using the widely used methods, such as the United States Bureau of Mines (USBM) method. Hence, a more accurate method is required. In this work, a full-process model is developed in COMSOL Multiphysics to describe the lost gas with time during the core recovery process as well as the desorption stage after the core is covered. In this method, by setting the initial gas pressure and flow parameters and matching the desorbed gas volume and considering variable diffusivity with respect to temperature, the initial gas content and the gas lost with respect to time are calculated. Overall, 10 field data are tested using this full-process model, and the USBM method is also applied to compare the results. It is found that if the ratio of lost gas volume estimated using the USBM method to the desorbed gas volume of the field data is lower than 2.0, the USBM method underestimates the lost gas compared to the full-process method; if the ratio is about 2.0, the results from the USBM and the full-process methods are comparable; and if the ratio is close to 3.0, the USBM method tends to overestimate the lost gas. The modeling results indicate that this proposed full-process method is more theoretically sound than the USBM method, which has high uncertainties depending on the number of desorbed gas data points used. Nevertheless, this proposed method requires a large number of parameters, leading to the difficulty in finding true parameters. Therefore, an optimization algorithm is required. In summary, this study provides theoretical support and a mathematical model for the inversion calculation of lost gas during shale core recovery. It is helpful to evaluate the resource potential and development economics of shale gas more accurately., Competing Interests: The authors declare no competing financial interest., (© 2022 The Authors. Published by American Chemical Society.)

Source rocks of the Mohe Basin, Northeast China are gas-prone and the organic matter has advanced to late oil-generation stages, producing condensate and natural gas. This provides suitable conditions for the Mohe Basin to become one of the most prolific terrestrial natural gas hydrate (NGH)-bearing areas in China. Knowing this, here we predict the depth and thickness of pure methane hydrate stability zones (HSZs) and gas hydrate stability zones (GHSZs) via simulating the hydrate-phase equilibrium and other formation P - T conditions. Furthermore, factors that have a major impact on the occurrence of HSZs are discussed. Results showed that the composition of gas (guest) molecules and the geothermal gradient are the two most controlling factors on HSZs. Moreover, it was found that a pure methane HSZ with a thickness of about 255 m can form in areas with a geothermal gradient of <1.5 °C/100 m, with top and bottom depth limits less than 493 m and greater than 748 m, respectively. In contrast, pure methane hydrates have difficulty forming, while hydrates from wet gas can form where there is a geothermal gradient of >1.6 °C/100 m. Furthermore, a wet gas HSZ with a thickness of at least 735 m can be expected when the geothermal gradient reaches 2.3 °C/100 m, with top and bottom depth limits at 115 and 850 m, respectively. Ultimately, a pure methane HSZ can still form in the abnormally high-pressured areas when the geothermal gradient is up to 2.0 °C/100 m. Overall, HSZs can occur due to the combined effect of formation temperature, pressure, and gas composition. Finally, based on the results from this study and drilling data, future successful hydrate drilling schemes can be implemented in the Mohe Basin and similar terrestrial areas., Competing Interests: The authors declare no competing financial interest., (© 2021 The Authors. Published by American Chemical Society.)

Having a clear understanding of the permeability variation mechanism is important for controlling the process of displacement of CH 4 with CO 2 in deep coal seams. Based on the stress-strain equation of porous elastic media and horizontal strain variations of coal, a mathematical model predicting permeability variation after CO 2 injection into gas saturated coal seams was established. The model shows that, during the displacement of CH 4 with CO 2 , the shrinkage strain of the coal matrix increases logarithmically with the decrease of pore pressure. With a decrease in the reservoir pressure, permeability rebound occurs with the influence of matrix shrinkage and gas slippage. Under low confining pressures, the rebounded permeability is high, and its associated rebound pore pressure is also high. For coals with a high cleat compression coefficient, the permeability decreases range is obvious. And permeability rebound only happens under low reservoir pressures. Coal properties, e.g., Poisson's ratio and Langmuir volume, show obvious influences in permeability variation during gas production. The model was also extended to predict permeability variation for a well-control area. During gas drainage process, the permeability in the well-controlled area first increases, then decreases, and then slowly returns to the original state with the lengthening of well-controlled radius. Under high confining pressures, the permeability decline range is more obvious. Also, correspondingly, the attenuation range of permeability increases and the rebound range decreases. The proposed model is beneficial in predicting permeability variations during the displacement of CH 4 with CO 2 , as well as guiding CO 2 injection into coal seams., Competing Interests: The authors declare no competing financial interest., (Copyright © 2020 American Chemical Society.)

The dynamic wetting for the CO 2 -water-silica system occurring in deep reservoirs is complex because of the interactions among multiple phases. This work aims to quantify the contact angle of CO 2 -water flow in the silica channel at six different flow velocities using molecular dynamics. The dynamic contact angle values at different contact line velocities are obtained for the CO 2 -water-silica system. By calculating the rates of the adsorption-desorption process of CO 2 and water molecules on the silica surface using molecular dynamics simulations, it has been found that the results of the dynamic contact angle can be explained by the molecular kinetic theory and predicted from the equilibrium molecular simulations. Moreover, the capillary pressure at different contact line velocities is predicted according to the Young-Laplace equation. The change in contact angles at different velocities is compared with empirical equations in terms of capillary number. The results of this study can help us better understand the dynamic process of the multiphase flow at the nanoscale under realistic reservoir conditions.