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Understanding the physical mechanisms of exploitation of such sources that occurs in the shale matrix in the middle and late stages is critical in the world’s energy supply. However, there is a current lack of research on the elusive relationship between mechanisms governing gas diffusion in shale matrices and the efficiency of gas production. In addition, various pores exist in a shale matrix within different diffusion mechanisms, affecting the mass transfer. In this work, we establish a microscopic model that considers the explicit interactions among various pore systems in the gas diffusion processes. The model was first verified with reported stress-dependent diffusion experimental data and then extended to the field scale. A sensitivity analysis was finally conducted to investigate the gas diffusion mechanism in gas production. The evolutions of the gas diffusion coefficient depended on the competition among the interactions, adsorption strain, and effective stress. “Production sensitive range” in which the shale gas production rate could be improved explicitly exists. Larger initial macroscopic and microscopic pore diffusivities can improve the early stage and overall gas-production efficiencies, respectively. Gas depletion is highly sensitive to extraction pressure in the middle and late production stages; as a result, adjusting the extraction pressure in a timely manner can improve the gas yield. In the deformable range, shale reservoirs with a large pore bulk modulus have better gas production rates in the middle stage. This work provides new insights into improving the gas production performance in the field.

In recent years, the exploration and development of continental shale in China have garnered significant attention. However, there remains a dearth of research on elastic parameter calculation and sweet spot evaluation for high clay content and strong anisotropy shale. In this study, the elastic parameters C11, C13, C33, C44, and C66of Gulong shale in the Qingshankou Formation of the Songliao Basin during the Cretaceous period were calculated using five predictive models for elastic coefficients based on core analysis and logging data. The accuracy of the calculation results obtained from different models was subsequently analyzed. First, based on the presence or absence of Stoneley wave patterns in acoustic logging, the estimation models for the five elastic stiffness coefficients can be categorized into two groups: models including ANNIE, M-ANNIE1, and M-ANNIE2 that utilize Stoneley wave logging data, and another group comprising M-ANNIE3 and V-reg models that do not require Stoneley wave logging data. By comparing the predictive performance with the measured values of C11, C13, and C66from core data, our findings demonstrate that the elastic coefficient derived from the M-ANNIE2 model exhibits superior agreement with experimental results. However, it is worth noting that the V-reg model demonstrates broader applicability in wells lacking array acoustic logging data. The Thomsen parameters, obtained through accurate calculation of elastic coefficients, reflect the strength of anisotropy and indicate that the Young’s modulus and Poisson’s ratio are reduced under its influence. Therefore, geostress calculations should incorporate an anisotropic model. The present study establishes a novel method for evaluating sweet spots based on rock elastic parameters, and its efficacy is demonstrated through an analysis of horizontal well production. This fast and straightforward evaluation approach holds promise as a valuable reference for other shale formations characterized by high clay content.

Directly obtaining representative pore structure information is important to understand subsurface shale gas storage and production, while acquiring large-scale and high-resolution images using a single imaging tool is plausible as there is always a trade-off between the resolution and field-of-view. We report a new method to define representative elementary volumes (REV) of a shale pore system and define pore structural parameters of diameter, surface area, porosity, and other features. Automated ultrahigh resolution scanning electron microscopy, integrated with a modular automated processing system (MAPS), was used to image pore distribution in two dimensions. Focused ion beam (FIB) milling was further utilized to construct a true three-dimensional digital image, on which the REV analysis was then carried out. The results show that (i) pores are mainly developed in organic matter (OM) and as interparticle inorganic pores and (ii) the diameter of inorganic pores is slightly larger than those in OM. The pore network coordination number, representing the average number of pores that are connected to a specific pore, indicates that the pores can be either clustered within mainly OM pores or more widely connected by slit-like pores and throats in minerals. Extracting cubic sub-blocks, ranging from 500 to 5000 nm in edge dimension, defines the minimum REV as ∼4000 nm, as measured using minimum and maximum pore sizes, surface areas, and shape factors. Combined FIB and MAPS provide insight into pore morphology and connectivity at multiple scales with the reconstructed digital rock used to determine representative REV sizes. Such results are useful in understanding the pore structure in shales and for the rapid acquisition of pore structure distributions.

The injection of CO2into shale reservoirs potentially increases rates and masses of CH4recovery and simultaneously contributes to the sequestration of CO2. At typical reservoir conditions (T≥31.08 °C, P≥7.38 MPa) the CO2will be supercritical. We compile, analyze, and supplement experimental data of shales from several basins across China, and use X-ray diffraction, scanning electron microscopy and low-pressure gas adsorption to characterize variations in shale pore structure before and after supercritical CO2(ScCO2) treatment, and supplement these with CH4/CO2adsorption experiments to characterize changes in shale adsorption capacity. The results show that clay and carbonate contents significantly decrease, and the relative content of quartz is increased after ScCO2treatment. Pore structure changes significantly after ScCO2treatment, with the majority of the shales showing a decrease in total specific surface area and total pore volume and an increase in average pore size — indicating the transformation of some micropores and smaller mesopores into mesopores and macropores. After ScCO2treatment, the experimentally derived absolute adsorption volumes of both CH4and CO2decrease, and the volumes of both CH4and CO2fitting a Langmuir isotherm decrease with an increase in treatment pressure and increase with an increase in temperature. The adsorption selectivity factors αCO2/CH4all remain greater than 1 with αCO2/CH4primarily controlled by the pore structure. The fractal dimension is positively correlated with Langmuir volume and negatively correlated with Langmuir pressure while the fractal dimensions are negatively correlated with αCO2/CH4. The selectivity factor αCO2/CH4decreases rapidly above a fractal dimension threshold (D1>2.65, D2>2.80). This paper further reveals critical interactions between ScCO2and shale and defines controls on and of pore structure and adsorption capacity to speculate on physical and chemical storage mechanisms of CO2in shale reservoirs. This provides several theoretical bases for shale gas recovery and the sequestration of CO2.

Hot Dry Rock (HDR) is a renewable energy source that has garnered attention due to its abundant reserves, widespread distribution, and consistent energy supply. However, the injection of cold water during the drilling and production process of HDR can alter the temperature of the rock in the HDR reservoir, leading to variations in its physical and mechanical properties near the wellbore. These changes can impact the stability and safety of the HDR wellbore. This study investigated the alterations in the physical and mechanical properties of HDR under different temperature conditions. The results revealed that there were negligible changes in the physical and mechanical properties when the temperature rose from 25 °C to 400 °C. However, noticeable changes occurred as the temperature increased from 400 °C to 800 °C, establishing 400 °C as the threshold for physical and mechanical property variations in the granite. Building upon these experimental findings, a segmented wellbore instability model was developed and validated. The model demonstrated that an increased temperature difference between the drilling fluid and the borehole corresponded to an expanded range of borehole failure. Furthermore, higher wellbore temperatures led to more pronounced disparities between the maximum and minimum principal stress of the borehole, rendering it more susceptible to instability. The research also uncovered that the optimal drilling position was influenced by temperature.

Continental shale oil is a new source of oil, and its formation and evolution mechanism is one of the most important scientific problems in its effective exploration and development. In this work, the hydrocarbon generation mechanism, occurrence of oil and gas, and pore structure characteristics were studied through a series of pyrolysis experiments using an improved closed experimental system, combined with chloroform extraction, two-dimensional nuclear magnetic resonance, and computed tomography, for the continental Gulong Shales, Songliao Basin. The results show that hydrocarbon generation from organic matter of continental Gulong shale follows a sequential reaction model, with adsorbed oil as an “intermediate” at Ro of 0.9–1.1%. The free oil reaches the generation peak and begins to convert to natural gas, and the gas/oil ratio increases rapidly when Ro > 1.3%. These suggest that the favorable oil generation window for Gulong shale is that Ro is between 0.9 and 1.6%. With oil generation, the shale pore structure and permeability change with maturity accordingly. The corresponding Ro for rapid porosity and pore volume increase is 0.9–1.2%, while Ro is greater than 1.2% for rapid permeability change as a result of the large amount of adsorbed oil converting into free oil. It is found that hydrocarbon generation and pore-forming materials are mostly lamalginite and the organic-clay complex, and their volumes shrank while generating hydrocarbon, forming pores and fractures along the layers and “sponge-like” pores, respectively. When Ro > 1.2%, the shale oil generation peak, pore development peak, and overpressure evolution peak are coupled, providing favorable conditions for shale oil and gas enrichment in continental Gulong shale. These experimental findings mutually prove and confirm the practice of Gulong shale oil exploration, and it may have important theoretical and practical significance for continental shale oil exploration and discovery in other basins.

Coal particles have a great importance in the production of coalbed methane. To reveal the relationship between the coal mechanical properties and the coal particles characteristics generated by the coal samples with different coal rank, coal failure experiments in the natural state and water-saturated state under triaxial compression are performed. The effects of coal rank, coal mechanical properties and water content on the characteristics of coal particles generated are investigated. The results show that the water-saturated sample has a lower compressive strength than the corresponding natural sample. Coal with different rank shows various fracturing modes after failure. Compared with the natural sample, the water-saturated sample generates more amount of coal particles. As coal rank increases, the amount of coal particles shows a 'U' shape trend, while there is a negative exponential correlation between the amount of coal particles and the compressive strength of coal. [Received: June 3, 2020; Accepted: April 10, 2021]

Shale reservoirs, characterized by their relatively low permeability and porosity, often employ hydraulic fracturing techniques to increase production during development. However, conventional large-scale hydraulic fracturing encounters challenges such as excessive water consumption, low flowback rates, and environmental concerns. Given the increasing scarcity of water resources and increased emphasis on sustainability environmental sustainability, hydraulic fracturing no longer meets the requirements for green and environmentally friendly extraction. The utilization of supercritical CO2fracturing technology emerges as a promising alternative, offering advantages such as reduced water usage and minimized environmental impact. Additionally, this technology allows for the sequestration of CO2underground, presenting an integrated approach to CO2geological storage and oil-gas extraction. Supercritical CO2possesses many unique physical and chemical properties. However, the micro-mechanisms governing its interaction with rock during fracturing, along with the mechanisms and propagation characteristics of fracture initiation, necessitate further in-depth investigation. This study aims to explore the development mechanisms of supercritical CO2fractures under the influence of single factor variables and natural fractures of different sizes (2 m, 4 m, and 6 m). To explore the interaction mechanisms between natural fractures and supercritical CO2fractures, single factor variable control experiments were conducted with natural fracture angles of 30 °, 45 °, and 60 °, and in-situ stress deviations of 3, 5, 7, and 9 MPa. Our research delves into the impact of natural fracture inclination angle, in-situ stress deviation, and natural fracture size on supercritical CO2fractures development. This comprehensive exploration unveils the intricate interaction mechanisms between natural fractures of different sizes and supercritical CO2fractures. Various control chart were studied, considering different natural fracture under diverse ground stresses and inclinations. The findings of this study bear theoretical significance and engineering application for enhancing efficiency in shale gas production.

Clay minerals contain a massive amount of nanopores and play a significant role in gas adsorption in shale. Although the pore structure of clay minerals has been widely studied, the characteristic of pores with diameter < 1 nm remains unclear. To investigate the pore characteristics of different clay minerals, especially for micropores, and to reveal the effect of pore structure on the methane adsorption capacity, the isotherm types, pore size distribution, pore volume, and surface area, as well as the CH4adsorption capacity of pure clay mineral samples, including kaolinite, montmorillonite, illite, and illite–smectite mixed layer (I/S), were investigated based on low-pressure N2and CO2adsorption and CH4adsorption isotherm measurements. The results show that the isotherm types of the studied clay minerals based on N2adsorption are all type IV, characterized by the presence of hysteresis loops. According to the features of hysteresis loops, it can be inferred that kaolinite mainly has cylindrical pores and slit-shaped pores, while pores in montmorillonite, illite, and I/S are dominated by inkbottle-shaped pores, with a small amount of slit-shaped pores. The studied clay minerals all display pore width peaks around 0.56–0.66 nm and 0.82–0.87 nm. Pores with diameters < 1 nm in kaolinite, illite, and I/S are all interparticle pores. Montmorillonite has microporous interlayer pores in addition to the interparticle pores, leading to its relatively large micropore volume and surface area. The CH4sorption capacity on different clay minerals is mainly influenced by the surface area, and montmorillonite has the highest CH4adsorption capacity.

The effective stress plays an essential role in predicting the permeability of the coal reservoir during coalbed methane (CBM) production. However, the importance of the effective stress coefficient (ESC) for permeability evolution has always been neglected. In this work, a series of permeability measurements were performed on cores of different directions under constant confining pressure (CCP) conditions and constant pore pressure conditions to demonstrate the different sensitivities of the anisotropic permeability on the confining stress and the pore pressure. Under CCP conditions, the loading and unloading results show that the irreversible permeability loss rate vertical to the bedding plane orientation is about 20% higher than that parallel to the horizon orientation. The in situ X-CT images indicate that the reason for irreversible permeability is that the microcleats cannot recover after the stress loading. The permeability variation with the increase of the Terzaghi effective stress presents an exponential law and a power law by changing the confining stress and changing the pore pressure for the same core, which suggests that the sensitivity of the permeability on the pore pressure is less than that on the confining stress. Then, the surface response method is used to calculate the ESC. The cores of different directions have different ESCs, ranging from 0.571 to 0.702. After correction of the ESC, the apparent permeability fits better with the effective stress. Finally, the role of the ESC in predicting the permeability during the CBM production is further investigated based on the S&D model. The modeling results indicate that the assumption of the effective stress coefficient as unity overestimates the increase of the effective stress during the reservoir pressure drawdown. The matrix shrinkage would dominate quickly for the lower effective stress coefficient. This study could be conducive to evaluate the stress sensitivity of coal reservoirs and predict the CBM production.

Hydraulic fracturing enhances the recovery of gas from ultralow permeability shales, into which water-based fracturing fluids, proppants, and activators are typically injected. However, the impacts of the existing complex multidomain response of a heterogeneous mineral and organic matrix and fractures on the resulting heterogeneity of reservoir transport properties caused by the hydraulic fracturing remain poorly understood. To address this defect, a multidomain multiphysics model is constructed to represent a two-phase flow within a three-component heterogeneous solid system (mineral and organic matrix and fractures) representing the functional complexity of the medium. This model partitions the shale reservoir into a stimulated reservoir volume (SRV) enclosed within an unstimulated reservoir volume (USRV). Different from the previous work, the shape of the SRV is treated as the spheroid instead of the rectangular shape and the size can be determined from the spatial distribution of microseismic events rather than artificially assumed. A two-phase flow model is established for both regions with the impacts of the effective stress variation on the fracture permeability considered and solved with a finite element formalism. The fidelity of the model is first verified using two field data sets from the Barnett and Marcellus shales with good fits achieved against time histories of production. Numerical studies then investigate the impacts of relevant parameters on shale gas production behavior; specially, the impacts of the effective stress and the existence of proppants are first reported. The variations in relative permeability and intrinsic permeability within the SRV are shown to dominate the early-time response of the gas flow rate. The long-term response is mainly dependent on the mass supply from the matrix system and the encapsulating USRV region. The effectiveness of hydraulic fracturing optimized as the SRV region is maximally extended in the horizontal direction and where the increase in permeability is a convex function against a concave function. The distal transport and placement of the proppant remarkably enhance the gas production rate and resist its decline as a result of the evolving high formation stress developed by pressure drawdown. For the selection of proppant type and placement, the resulting permeability and compressibility are of complementary importance as the first controls the initial gas flow rate, whereas the second determines the permeability trend with time. Proppant permeability decreases near-linearly for a constant compressibility but exponentially where compressibility is updated to represent the true response of the proppant pack. The proposed model applies a new approach for optimizing the hydraulic fracturing process and for analyzing the shale gas production behavior.

A proper understanding of the compressibility characteristics of propped fractures is crucial to the accurate prediction of coalbed methane production and the proper deployment of development strategies due to the application of hydraulic fracturing. In this article, online nuclear magnetic resonance experiments and improved analytical models were integrated to characterize the variable compressibility of propped fractures in coal. Experimental results demonstrated that a higher concentration or smaller size of proppant results in a lower compressibility of the propped fracture. It is also shown that the compressibility of propped fracture exhibits an obvious stress-sensitive behavior. Specifically, with increasing effective stress, the compressibility of proppant fracture gradually decreases, and the decrease is significant at low effective stress but gradually stabilizes at high effective stress. Analysis based on the proposed model showed that increasing the proppant concentration is an effective method to reduce the impact of the Young’s modulus of coal on the compressibility of propped fracture, while the impact of Poisson’s ratio of coal on the compressibility of propped fracture is negligible. Moreover, a larger Poisson’s ratio and Young’s modulus of proppant can effectively reduce the compressibility of propped fracture. The stress sensitivity of propped-fracture compressibility increases significantly with an increase in proppant concentration or a decrease in proppant size, whereas the effects of mechanical properties of coal and proppant are negligible.

The stability and mobility of proppant packs in hydraulic fractures during hydrocarbon production are numerically investigated by the lattice Boltzmann-discrete element coupling method (LB-DEM). This study starts with a preliminary proppant settling test, from which a solid volume fraction of 0.575 is calibrated for the proppant pack in the fracture. In the established workflow to investigate proppant flowback, a displacement is applied to the fracture surfaces to compact the generated proppant pack as well as further mimicking proppant embedment under closure stress. When a pressure gradient is applied to drive the fluid-particle flow, a critical aperture-to-diameter ratio of 4 is observed, above which the proppant pack would collapse. The results also show that the volumetric proppant flowback rate increases quadratically with the fracture aperture, while a linear variation between the particle flux and the pressure gradient is exhibited for a fixed fracture aperture. The research outcome contributes towards an improved understanding of proppant flowback in hydraulic fractures, which also supports an optimised proppant size selection for hydraulic fracturing operations.

Injecting oxy-coal combustion flue gas into deep coal seams is viable to simultaneously reduce the main anthropogenic greenhouse gas (GHG) CO2and gaseous contaminants SO2and NOx. This paper investigates the adsorption and desorption behaviors of N2O on different rank coals from peat to anthracite. The potential adsorption mechanism is also elucidated. The results show that the Sips model can well describe the equilibrium relationship of N2O adsorption on coals. The fitting results derived from the Sips model indicate that the adsorption affinity of N2O on coals decreases with the increasing coal rank, while the heterogeneity of the adsorption system tends to be stronger with the decreasing coal rank. The micropore surface area of coals greatly determines the maximum adsorption capacity of N2O derived from the Sips model. The kinetics process of N2O adsorption on coals follows the simplified bidisperse model, and it is controlled by the micropore diffusion. The apparent diffusion coefficient in micropores mainly depends upon micropore surface area of coals. The adsorption and desorption process of N2O on the high-rank Fumin (FM) coal (Ro,max= 2.59%) is a completely reversible and physical adsorption process. In contrast, the adsorption and desorption hysteresis of N2O on coals becomes more significant with the coal rank decreasing from 0.83 to 0.23%, indicating that the chemical adsorption of N2O exists for the low-rank coals. The X-ray photoelectron spectroscopy characterization further reveals that the oxygenic and nitric speciation compositions of the high-rank FM coal after N2O adsorption remain unchanged. However, the oxygenic functional groups in the low-rank coals act as the main active sites for the chemical adsorption of N2O. Interaction with N2O only increases the total nitrogen content of the three low-rank coals but also changes their nitric speciation compositions, which are characterized by the increasing content of pyridine N and oxide N and the decreasing content of pyrrole/pyridone N. The aforementioned chemical adsorption is beneficial for stable storage of N2O in the target coal seams with a low metamorphic degree.

The dynamic wetting for the CO2–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 CO2–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 CO2–water–silica system. By calculating the rates of the adsorption–desorption process of CO2and 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.

The impact of moisture on gas adsorption capacity reduction on coal has been well recognized, and empirical correlations are widely used to quantitatively evaluate the moisture effect. However, few studies are found on fundamental modeling of the moisture effect on gas adsorption capacity. In this work, two theoretical models on the basis of the extended Langmuir theory (EL-based) and the ideal adsorbed solution theory (IAS-based) were developed to account for the gas adsorption capacity with different pressures and moisture contents. With the parameters determined from the gas adsorption on dry samples and water adsorption on samples under atmospheric conditions, both models are able to predict the gas adsorption capacity under combined effects of gas pressure and moisture content. The models were verified through a set of experimental data from a coal sample from Australia, and they were further applied to describe the methane adsorption behavior on a coal sample from New Zealand. The results demonstrate that both models can reasonably predict the gas adsorption capacity on moist coal samples. Although one more parameter is required, the IAS-based model could match the experimental data with higher accuracy. The research findings in this work contribute to a better understanding of the fundamentals of gas adsorption characteristics on moist coal.

Gas production from multiple coal seams has become common practice in many coal basins around the world. Although gas production rates are typically enhanced, the economic viability of such practice is not well studied. In order to investigate the technical and economic feasibility of multiple coal seams production, reservoir simulation integrated with economics modelling was performed to study the effect of important reservoir properties of the secondary coal seam on production and economic performance using both vertical and horizontal wells. The results demonstrated that multiple seam gas production of using both vertical and horizontal wells have competitive advantage over single layer production under most scenarios. Gas content and permeability of the secondary coal seam are the most important reservoir properties that have impact on the economic feasibility of multiple seam gas production. The comparison of vertical well and horizontal well performance showed that horizontal well is more economically attractive for both single well and gas field. Moreover, wellhead price is the most sensitive to the economic performance, followed by operating costs and government subsidy. Although the results of reservoir simulation combined with economic analysis are subject to assumptions, multiple seam gas production is more likely to maintain profitability compared with single layer production.

Rock uniaxial compressive strength is a vital rock mechanics parameter, which accurate assessment is critical for high-efficiency unconventional reservoir development. However, its realization for standard cores is quite problematic due to difficulties and high costs related to the collection and preparation of samples. Unconventional fracturing treatment have evolved from single to composite lithology. This study collected shale and sandstone samples at different bedding angles (0°, 45°, 90°)to prepare the sandstone-shale composite samples at different interlayer ratios. It measured the prepared composites’ longitudinal wave and transverse wave velocities with ultrasonic velocity testing. The uniaxial compressive strength of the sandstone-shale composites with various bedding angles were tested via a servo rock triaxial testing machine. The anisotropic characteristics of the prepared sandstone-shale composites with various bedding angles were analyzed, and relation between the uniaxial compressive strength of the anisotropic sandstone-shale composite and P-wave velocity was derived and experimentally validated. The results show that: the wave velocity test results of the sandstone-shale combination show that with the increasing proportion of shale, the wave velocity of the longitudinal wave and the transverse wave both increase; The wave velocity results of different bedding planes in shale are as follows: Vp(0°)> Vp(45°)> Vp(90°). The average P-wave and S-wave velocities at 45° are 0.92, while the average P-wave and S-wave velocities at 90° are 0.85 compared to 0°; the P-wave and S-wave anisotropy of shale are both 0.14, and the shale shows significant anisotropy. In the sandstone-shale composite, the uniaxial compressive strength gradually decreases and the strain increases with the increase of shale proportion. The value of uniaxial compressive strength is UCS(0°) > UCS(90°) > UCS(45°). Based on the P-wave modulus, a fitting relationship formula for the uniaxial compressive strength of sandstone-shale composites with different bedding angles and interlayer ratios was established and verified. The anisotropic strength predictive formula established based on experimental data is simple, precise, and easy to obtain, with strong practicability. The present research results can provide proper technical support for sandstone-shale composite fracturing optimization and reservoir development.

Coal seams with high CO2gas contents can be difficult to drain gas for outburst management. Coal has a high affinity for CO2with adsorption capacities typically twice that of CH4. This paper presents an analysis of nitrogen injection into coal to enhance drainage of high CO2gas contents. Core flooding experiments were conducted where nitrogen was injected into coal core samples from two Australian coal mining basins with initial CO2gas contents and pressures that could be encountered during underground mining. Nitrogen effectively displaced the CO2with mass balance analysis finding there was only approximately 6%–7% of the original CO2gas content residual at the end of the core flood. Using a modified version of the SIMED II reservoir simulator, the core flooding experiments were history matched to determine the nitrogen and methane sorption times. It was found that a triple porosity model (a simple extension of the Warren and Root dual porosity model) was required to accurately describe the core flood observations. The estimated model properties were then used in reservoir simulation studies comparing enhanced drainage with conventional drainage with underground in seam boreholes. For the cases considered, underground in seam boreholes were found to provide shorter drainage lead times than enhanced drainage to meet a safe gas content for outburst management.

A simulation study of partial coal pyrolysis to improve the petrophysics of coal seams and ultimately extract higher methane yields with accompanying pyrolysis gases was conducted, which was used to investigate the feasibility of partial coal pyrolysis for enhancing coalbed methane (CBM) recovery. Enhancing CBM production is an important subject for current CBM development, especially for low permeability coals. CBM exists mainly in an adsorption state in multiple micropores, which increases the complexity of CBM production. Pore volume and porosity in the low rank coal increased with increasing temperature. The permeability of the low rank coal increased exponentially with increasing temperature (300–400 °C) due to the generated pore–fractures. The excessively high temperature of pyrolysis could result in the coals with the highest pore volume possessing the lowest methane adsorption capacity due to the extent of graphitization. Partial coal pyrolysis in a subsurface can increase the gas content, and improve the seepage ability of a CBM reservoir. CBM gas-in-place can be vastly increased (almost seven times the original CBM gas-in-place) by thermal treatment. The results indicated that the peak of daily gas production greatly increased and the gas yield peak arrived in advance for different rank coals with thermal treatment. By means of F.A.S.T. numerical software, gases in place and gas production for coal reservoirs after thermal treatment were acquired, which demonstrated that injected heat could promote CBM desorption, increase the coal permeability, and improve CBM production. Therefore, this technique may have significant implications for enhancing CBM recovery.

CO2injection into coal seams is a non-isothermal process, which has significant impact on coal permeability but has not been well studied. In this paper, a non-isothermal model coupled with nonlinear gas flow and matrix deformation was developed. The effects of temperature change on each term of the effective strain during the CO2injection scenarios, as well as the variations of fluid properties over a range of sub- and supercritical-thermodynamic conditions were investigated. This model involves the balance of thermal energy and the law of heat transfer. Two non-isothermal cases of CO2injection were studied and compared with the isothermal case. The results show that CO2injection into coal seams reduces coal permeability for all three cases. The coal matrix expands with temperature increase due to the thermal expansion and shrinks due to the decrease in adsorption amount. However, the final permeability with low-temperature CO2injection remains lower than that with high-temperature gas injection since the effect of sorption-induced strain on permeability outweighs that of the thermal deformation. The increase in temperature leads to the reduction in coal swelling (with the decrease of CO2adsorption capacity), resulting in larger cleat aperture and higher coal permeability for the cases studied in this work. [Received: November 29, 2015; Accepted: June 22, 2016]

The behavior of stress-dependent permeability has been an important research topic for oil/gas production. The majority of permeability models for porous media have been proposed based on porelasticity theory. The matrix is assumed to be thoroughly separated by pores in the models and the pore compressibility is used to represent the stress-dependent behavior of permeability. However, matrix could not be separated by pores thoroughly and the impact of stress concentration around pores on pore deformation and permeability should be considered. In this study, the impact of stress concentration on permeability was illustrated by numerical simulation. In addition, the mechanism of stress-dependent behavior of permeability was analyzed. Since it is difficult to establish theoretical permeability models involving stress concentration effect caused by the complex pore structure, machine learning was applied in this paper. One of the four capable machine learning methods was selected and the corresponding machine learning model was validated through both numerical and experimental data. Moreover, the different performance of permeability prediction between the conventional model and the proposed one was discussed. The results indicate that the stress-dependent behavior of permeability results from stress concentration rather than the pore bulk modulus. Therefore, the stress-dependent permeability model with the impact of stress concentration is more accurate, compared with the numerical results and experimental data. In addition, the stress concentration increases the pore deformation and induces strong stress-dependent behavior of permeability, which is sensitive to pore shapes and related to the pore shape complexity. Specifically, the impacts of pores with different shapes on permeability are similar if the complexity index of pore shape is under 0.6 or over 0.9 and distinct for the value in between. Furthermore, the alteration in the magnitude and orientation of the stress affects stress dependency of permeability, which increases with the pore shape complexity. If the complexity index of pore shape exceeds 0.96, the alteration of permeability induced by change in stress orientation can be over 64%.

Sorption isotherms of hydrocarbon and carbon dioxide (CO2) provide crucial information for designing processes to sequester CO2and recover natural gas from unmineable coal beds. Methane (CH4), ethane (C2H6), and CO2adsorption isotherms on dry coal and the temperature effect on their maximum sorption capacity have been studied by performing combined Monte Carlo (MC) and molecular dynamics (MD) simulations at temperatures of 308 and 370 K (35 and 97 °C) and at pressures up to 10 MPa. Simulation results demonstrate that absolute sorption (expressed as a mass basis) divided by bulk gas density has negligible temperature effect on CH4, C2H6, and CO2sorption on dry coal when pressure is over 6 MPa. CO2is more closely packed due to stronger interaction with coal and the stronger interaction between CO2molecules compared, respectively, with the interactions between hydrocarbons and coal and between hydrocarbons. The results of this work suggest that the “a” constant (proportional to Tc2/Pc) in the Peng–Robinson equation of state is an important factor affecting the sorption behavior of hydrocarbons. CO2injection pressures of lower than 8 MPa may be desirable for CH4recovery and CO2sequestration. This study provides a quantitative understanding of the effects of temperature on coal sorption capacity for CH4, C2H6, and CO2from a microscopic perspective.

Pore structure of Chinese coals with heating and pressurization treatments was studied using small angle X-ray scattering (SAXS), N2adsorption/desorption isotherms and scanning electron microscope (SEM). SAXS was performed for some samples after heat treatment at seven elevated temperatures from 25 to 250° at 0 MPa and for other samples with hydrostatic pressure treatment at 0, 5, 10, 15 and 20 MPa at the room temperature. The results show that N2 adsorption isotherm together with SAXS could be a comprehensive method to evaluate the pore shape and the pore size distribution: the pore shapes are generally spherical for low rank coal and they are mainly ellipsoidal for high rank coal. All these measurements were then interpreted using the fractal theory to reveal relationship between surface fractals and coal rank, and the evolution of surface fractals under heating and pressurization treatments. The results show that surface fractal dimension (Ds) changes with different treating temperature and pressure and maximum vitrinite reflectance (Ro,m). Especially in the bituminous stage, Dsshows an increasing trend with Ro,munder varied temperatures. Moreover, Dsshows an increasing trend with increasing temperature before 200°, and a decreasing trend after 200°. Furthermore, the results show that Dshas a more complex relationship with Ro,munder varied treating temperature than that under varied treating pressure.

Shale oil has received increasing attention as an essential replacement for conventional oil resources. Shale oil recovery is a complex process controlled by interactions of many factors whose impact could be significantly different from conventional reservoirs. This study hence aims to fill the gaps in the literature by studying various aspects of the phase behavior of shale oil and their significance in different aspects of the recovery from oil shale. In the first part of this study, the standard practices, including experimental and theoretical methods for calculating the pressure, volume, temperature (PVT), and phase behavior of shale oil, is discussed in detail. Next, the effects of factors such as the composition of fluids, pore structure, and capillary forces on the phase behavior of hydrocarbon fluids are explained. The third part focuses on applying phase behavior for oil shale development. Moreover, the geological and geochemical processes that lead to the maturity of kerogen, the formation of shale oil, and the experimental methods by which those processes are currently studied are scrutinized. By studying the thermal and burial history of the hydrocarbon-generating strata and hydrocarbon-generating kinetics, the shale formation’s oil and gas phase distribution can be predicted. Consequently, the sweet spots for the recovery of light condensate oil can be more accurately determined. The application of enhanced oil recovery methods is an inevitable part of recovery from conventional and unconventional formations. Therefore, the last part of this study analyses the changes in the phase behavior of shale oil when an external component, i.e., CO2or CH4, is injected into the reservoir. Reviewing the literature revealed that a more accurate prediction of hydrocarbon phase behavior can be made by combining different disciplines of science to achieve optimized plans for efficient shale oil development, making shale oil a more economically viable energy resource.

Co-production of gas from both coalbeds and tight formations is considered a viable means to improve well productivity. Most previous studies focused on the geology and resource estimates for gas production viability with little attention to the effectiveness of gas co-production with regard to well types. To make up for this weakness, a two-phase flow and reservoir deformation coupled model is proposed together with an anisotropic permeability model. The coupled model is first verified using gas and water production data from a vertical well from the Linxing block in the Ordos Basin, China. Then a reservoir model is built, including one coal seam and one tight gas formation separated by a low-permeability stratum with four simulation scenarios designed. Based on the results, the impacts of the crossflow between different reservoirs are addressed and the mechanisms of the gas co-production rate profile types observed in the Linxing block are analyzed. It is also found that high water-saturated adjacent reservoirs would keep the water relative permeability of the gas-rich reservoir at a high level, impeding the gas flow. The use of a horizontal well is strongly recommended when most gases are stored in a specific thin reservoir and the life of the well is short; however, a vertical well is favored when two or more gas-rich and high permeability reservoirs co-exist and the well life is relatively long. For the application of vertical wells, the hydraulic fractures should extend in the horizontal planes and interact with the pre-existing natural fracture. For horizontal wells, the hydraulic fracture should extend in the host reservoir and penetrate into the adjacent strata. This work can shed new light on the co-exploitation of coal measure methane.

Understanding the evolution of permeability during rock shear displacement plays an important role in many geosciences and geo-engineering, such as shale gas exploitation. In previous studies, permeability data were obtained under different experimental conditions with varied in situ stress environments, fracture apertures, or loading stresses. However, the mechanisms controlling the permeability evolution during the shear process have not been well explained. In this study, two special conditions, fractures with constant stiffness (CS) and constant volume (CV), are proposed to define the upper and lower boundaries of permeability evolution. An inverted “L-shaped” model containing a matrix and fracture was established to investigate the permeability evolution and internal morphological changes in the fractures. The impacts of the initial fracture aperture and normal stress in the shear process are discussed together with the apparent fracture aperture, effective flow area, and pore throat radius. Under the CS condition, the self-supporting effect produced by the contact between the upper and lower fracture surfaces plays a dominant role in changing the permeability, and three stages of permeability evolution with shear displacement are observed: rapid increase, slow increase, and decrease. Under CV conditions, the submergence effect of the fracture closed the effective flow channels, thereby reducing the permeability in three stages: rapid decrease, slow decrease, and recovery. The model results show that both a smaller initial fracture aperture or a greater normal stress lead to a greater variation in the permeability and the roughness of fracture surface determines the permeability evolution range. The new model was applied to generate a series of shale permeability evolution boundaries under different limit conditions. These boundaries are consistent with experimental observations reported in other literatures. This work provides new insights into the permeability evolution of rock strata under shear action.

Abstract: Microwave irradiation is widely applied as a heating method since this approach avoids the intrinsic limitations of heat transfer via conduction. However, microwave heating in highly heterogeneous materials, such as rocks, remains poorly understood. Current approaches applied to rocks typically ignore (i) state transformations of liquid and solid, (ii) impacts of the temperature-dependent dielectric permittivity and specific heat capacity, and (iii) innate microscale mineral heterogeneities in the evolution of temperature within mineral aggregates. We address these limitations with a dual-component effective-medium approach. In this approach, mineral aggregates in the shale matrix are separated into high- and low-transformative-capability materials (HTC and LTC systems), coupled by heat transfer. The temperature increase in the HTC and LTC systems is affected by both microwave irradiation and heat transfer. The temperature differential between these two systems increases with increasing irradiation time, and heat transfer acts to ameliorate this differential. A three-stage temperature-evolution profile is replicated for rocks comprising linearly increasing, stable and rapidly increasing stages. The peak in the specific heat capacity-temperature curve is the main contributor to the plateau stage. Additionally, in the case of a high heat transfer coefficient, all three stages can be observed in both systems, while in the case of a low heat transfer coefficient, not all three stages occur. The impact of the real part of the dielectric permittivity is not universal, while a higher value of the imaginary part results in a larger increase in temperature. This work proposes an alternative approach to simulate the microwave heating process in heterogeneous materials. Highlights:

Mineral aggregates in the rock matrix are separated into high- and low-transformative capacity systems, coupled by heat transfer.

A dual-component effective-medium approach considering the above two systems is proposed to simulate the microwave heating process in heterogeneous rocks.

A three-stage temperature-evolution profile is replicated for rocks comprising linearly increasing, stable and rapidly increasing stages.

Shale oil has become an important oil resource over the past decade. The oil storage behavior, including the adsorbed oil and free oil, is one of the most important controlling factors for shale oil production. Because the shale oil storage behavior is largely determined by the fluid and solid interactions, this review first evaluates the shale mineralogy, pore structure, and oil properties. Then, the experimental methods to characterize the free oil and adsorbed oil are reviewed. The relationship between the oil storage behavior and shale and oil properties are then discussed. It is concluded from the literature work that the organic matter has the highest adsorption capacity for oil, followed by clay minerals, quartz, and calcite. While it is well-known that heavier oil components are adsorbed more than the lighter components, a relationship between the ratio of pore size to oil molecular size and the ratio of free oil to adsorbed oil is suggested and plotted. Finally, it is found from the literature that accurate experimental methods and theoretical models on free oil and adsorbed oil characterization are still missing; therefore, these topics require attention in future researches on shale oil.