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In this work, a triple-porosity, two-phase flow model was established to fill the knowledge gap of previous models focusing on gas production characteristics while ignoring the impacts of water injection. The proposed model considers the water flow in the fracture systems and clay minerals and the gas flow in the organic matter, inorganic pore, and fracture systems. The proposed model is solved using a finite element approach with COMSOL Multiphysics (Version 5.6) and verified with field data. Then, the evolutions of the intrinsic and relative permeabilities during water injection and gas production are examined. Furthermore, the impacts of water injection time and pressure are investigated. Good verification results are obtained; the goodness-of-fit value is 0.92, indicating that the proposed model can replicate both the water stimulation and the gas production stages. The relative gas permeability declines during water injection but recovers in the gas depletion stage. Furthermore, the intrinsic permeability increases during the water injection stage but decreases during the gas production stage. A higher water injection pressure and longer injection time would enlarge the intrinsic permeability, thus improving flow capacity. However, it would reduce gas relative permeability, thereby hindering gas flow. The shale gas production characteristic is controlled by the two abovementioned competing mechanisms. There exists a perfect combination of water injection pressure and injection time for achieving the maximum profitability of a shale gas well. This work can give a better understanding of the two-phase flow process in shale reservoirs and shed light on the field application of hydraulic fracturing. [ABSTRACT FROM AUTHOR]

Abstract Shale permeability and its variation under high stress are vital for gas production from deep shale gas reservoirs. Most experiments of stress-dependent permeability for organic-rich shale were conducted under lower stress less than 40 MPa, therefore, shale permeability evolution under high stress is not clear. In this work, the effects of high stress on the permeability and fracture compressibility of shales were investigated experimentally. Moreover, the impact of stress cycling on permeability were also studied. Four shale samples including two intact samples and two fractured samples from Cambrian Niutitang Shale formation and Silurian Longmaxi Shale formation were used. Permeability was measured using Helium under different stress conditions, including different confining pressure, different gas pressure, and constant effective stress. The highest effective stress and gas pressure in this work was 59.5 MPa and 10 MPa, respectively. Fracture compressibilities were calculated using the stress-dependent permeability data. The results show that the permeability of the intact samples and fractured samples decreased by one order of magnitude and three orders of magnitude, respectively, with the effective stress changing from 1.5 MPa to 59.5 MPa. The shale permeability results show a two-stage characteristic and nonlinearly decreasing trend with the increase of effective stress, demonstrating that the fracture compressibility is stress dependent and decreases with stress. The permeability hysteresis occurs between the loading and unloading cycles due to the inelastic compression of the pore. The modelling results also show that the Klinkenberg constant show a positive correlation with effective stress, as effective stress reduces the fracture opening and absolute permeability. Highlights • Permeability is strongly sensitive to stress for shales. • Fracture compressibility decreases with increase of stress. • Fracture compressibility of the fractured shale samples are more sensitive to the effective stress change. • Absolute permeability decreases with effective stress and Klinkenberg constant increases with effective stress. [ABSTRACT FROM AUTHOR]

With the increasing demand in natural gas and interest in greenhouse gas sequestration, gas transport mechanism and gas-induced deformation of shale have become important research topics. The shale matrix swells after adsorbing gas, which will impact on the gas transport behaviour in shale. In this paper, the kinetic shale swelling and kinetic gas adsorption in different types of gases at various gas pressures under confining pressure of 20 MPa and temperature of 25 °C were investigated. The gases used in the tests were helium, N 2 , CH 4 and CO 2 . It was found that shale swelling under this experimental conditions has two components: strain caused by poroelasticity and gas adsorption-induced swelling strain. The experimental results show that gas adsorption induced shale swelling and the absolute adsorption amount in different gases are both about one order of magnitude lower than that of coal and are in a trend line with the results of gas adsorption-induced coal swelling, indicating that shale swelling mechanism may be similar to that of coal. The swelling rate of shale has a positive correlation with the mass rate of gas uptake. Moreover the swelling rate of shale in helium is the highest, and that in CO 2 is the lowest due to slow gas diffusion caused by larger CO 2 adsorption-induced swelling and CO 2 phase transition from vapor state to liquid state at the experimental condition in this study. The swelling rate of shale in CH 4 and N 2 are almost the same. Helium-induced swelling rate increases with gas pressure due to the change of effective stress, while the swelling rates of shale in CH 4 , N 2 and CO 2 are positively correlated to the gas pressure in the early stage and negatively correlated in the later stage due to the different adsorbing gas transport mechanism in macropores and micropores. The phase change of CO 2 leads to the change in density and viscosity, resulting in the change of kinetic swelling rate. It was also found in this work that the anisotropy ratio for shale swelling decreases in the order of He, N 2 , CH 4 and CO 2 . Gas adsorption results in a lower anisotropy ratio, which may be related to the more random distribution of the organic matter and clay minerals, where gas adsorption and its induced swelling occur. [ABSTRACT FROM AUTHOR]

Gas is stored in shale mainly in free and adsorbed phases. Since a significant amount of gas in the shale is adsorbed to the organic matter and/or clay minerals, it is possible that gas adsorption will induce shale swelling, which may then has an impact on the gas flow behavior in the shale thus its gas production. In this work, strain behavior was studied in two gases, helium and methane, at different pore pressures under constant hydrostatic pressure at 20 MPa on two shale samples. The results show that porosity and volumetric strain are functions of gas pressure and the strain is larger in methane than helium demonstrating gas adsorption induced swelling for the shale samples. The calculated methane adsorption induced swelling strain is at a magnitude of 0.1% volumetrically with pressure at 10 MPa for the shale samples studied. The adsorption induced shale swelling strain shows a Langmuir-like relationship with pressure and is proportional to the amount of methane adsorbed. The results also show slight anisotropic strain behavior between the two directions of parallel and perpendicular to the bedding and strain hysteresis with methane in and out of the shale. The gas adsorption induced swelling may influence gas flow in gas shale, thus more research in this topic is warranted. [ABSTRACT FROM AUTHOR]

Proppants hold fractures open and increase fracture conductivity but must survive and remain functional during pressure drawdown. The shale reservoir usually suffers a high effective stress during gas depletion whilst most previous experiment works are conducted under a relative low stress level. In this work, permeability evolution was explored in a proppant-supported natural fracture of Longmaxi shale from the Sichuan Basin, China under a large effective stress range (1.5–59.5 MPa). Proppant performance was examined via continuous permeability measurements and by optical microscopy and laser-classifier measurements of particle size distributions (PSD) recored both pre- and post-loading. The permeability of the propped shale fracture is two orders of magnitude higher than that of the non-propped fracture and strongly controlled by the proppant behaviour. Surprisingly, overall permeability of the proppant pack decreases with an increase in thickness of the enclosed proppant. The decrease in the permeability with high stresses is largest for unpropped fractures and decreases with an increase in the number of layers. Most important, the mean compressibility of the non-propped and propped fracture is not constant but reduces with an increase in confining stress. This indicates that the compaction, crushing, embedment and repacking of the proppant particles, because of high effective stress, resulting in a decrease in the porosity of the proppant pack further reducing the compressibility and permeability of the supported fracture. • Permeability evolution was explored in a proppant-supported natural fracture under high (1.5–59.5 MPa) effective stress. • Proppant performance was examined via permeability measurements and particle size distributions (PSD) recored. • Overall permeability of the proppant pack decreases with an increase in thickness of the enclosed proppant. • The mean compressibility of the non-propped and propped fracture reduces with an increase in confining stress. [ABSTRACT FROM AUTHOR]

Microwave heating fracturing is potentially a green stimulation technology for gas shale recovery. However, the mechanism together with permeability evolution of microwave irradiated reservoir remain unclear. To fill this knowledge gap, the responses of Longmaxi shale from the Sichuan Basin, southwest China, to both continuous and intermittent microwave stimulation along variable microwave heating paths were explored. A complex thermally-induced fracture network can be formed gradually without sudden collapse under intermittent microwave irradiation. Changes in the petrophysical parameters of the shale including wave velocity, weight and volume at different intermittent microwave irradiation steps were measured together with temperature variation. The evolution of permeabilities for the two shale samples with alternately parallel and vertical beddings at different effective stresses was analyzed both before and after microwave irradiation. After the last step of intermittent microwave irradiation in this study, the shale permeability increased by two to four orders of magnitude for the shale sample with flow parallel to bedding and one to two orders of magnitude with flow perpendicular to bedding. Microwave treatment accentuates the anisotropy between bedding-parallel and bedding-normal permeabilities. Evolving pore size was measured by high-pressure mercury porosimetry and thermal-induced fracture characteristics and the changes of mineral composition were characterized by SEM combined with Energy Dispersive Spectroscopy (EDS). Thermally- and chemically-induced swelling stresses are mainly responsible for the development of fractures and micro-porosity in the shale. A permeability model with variable compressibility coefficient was adopted to fit the experimental data for shale permeability across a wide range of effective stresses from 2.5 MPa to 59.5 MPa. Shale fracture compressibility decreases in the later stage of microwave irradiation, suggesting the hardening of thermal-induced fractures. • Response of Longmaxi shale to variable microwave heating paths were explored. • The evolutions of permeabilities were analyzed both before and after microwave radiation. • A complex heating-induced fracture network was generated under the intermittent microwave radiation. • After microwave irradiation, the shale permeability increased by two to four orders of magnitude. • Microwave treatment accentuated the anisotropy between bedding-parallel and bedding-normal permeabilities. [ABSTRACT FROM AUTHOR]

• Permeability is represented by the evolving nanotube radius surrounded by matrix. • Permeability response is competition between local strain and matrix global strain. • The reason of the upright limb of the "U"-shaped permeability profile is explained. • The impact of inhomogeneities of matrix on permeability evolution is addressed. Understanding the evolution of shale permeability is critical in efficiently recovering gas from shale reservoirs. Two representative profiles of permeability evolution are typically experimentally observed under constant confining pressure and incremented gas pressure – "U-shape" with increasing gas pressure but sometimes absent the second upright limb of the "U" at high gas pressures. Current models fail to address these two different profiles, potentially leading to inappropriate explanation of experiment observations or inaccurate predictions of gas production. In order to determine the mechanistic reason, a multi-layer nanocased model, in which transmissive nanotubes are embedded within a cylindrical sheath of matrix, is proposed. In the model, permeability evolution is defined as a function of the evolving nanotube radius within a total matrix radius. The ensemble structure governs the transition from local deformation of the nanotube wall to the global deformation of the matrix sheath, particularly as sorbing/swelling gas gradually permeates the sheath wall. The finite element method is employed to calculate permeability evolution from an initial equilibrium state to final equilibrium. We develop a series of permeability evolution curves that match various experimental profiles. Contrasting observed permeability responses are attributed to the competition between nanotube strain and matrix global strain. The former term enlarges the nanotube radius while the latter term swells the matrix declining the permeability value. Therefore, when the matrix global strain dominates at late time, permeability decreases. Conversely, a permeability recovery stage is barely observed in the late stage because in most cases global swelling dominates the permeability evolution and an extended observational period is necessary before this swelling appears. This is also the reason why the observed final permeability ratio is rarely greater than unity. A small nanotube radius or a large adsorption strain favors a significant decrease in permeability. When the nanotubes are located within the inorganic matrix, the permeability profile conforms to poro-elastic theory and the decreasing permeability stage is barely apparent or absent. The proposed model thus provides insight into the controls on permeability evolution in shales and the controlling impact of shale matrix properties by considering the inhomogeneities of the shale matrix. [ABSTRACT FROM AUTHOR]

Shale gas has played an increasingly important role in world energy supply in recent years. The gas transport process in the shale matrix is particularly important as it affects the long-term production behavior of shale gas. The shale matrix consists of inorganic minerals and embedded organic matter with mass transfer influenced by mechanical interactions. We develop a micro-scale discrete coupled model to explicitly account for mass transfer and mechanical interactions, and how these interactions affect the gas transport characteristics of both components. Specifically, the model comprises organic matter embedded within inorganic minerals. The proposed model is implemented and solved within the framework of COMSOL Multiphysics (Version 5.4). The model is first verified against the results of a desorption-diffusion-seepage coupled experiment and then extended to field scale. It is found that the impacts of gas pressure and effective strain are different for the gas seepage in inorganic minerals and gas diffusion in organic matter. Gas pressure may enhance the permeability of the inorganic phase due to the gas slippage effect while compactive effective strain decreases permeability during the gas depletion process. For gas diffusion in the organic matter, surface diffusion decreases and effective diffusion coefficient increases with declining gas pressure. While the impacts of effective strain on the effective diffusion are dependent on the external boundary conditions, the effective diffusion coefficient is lower than the initial value under constant stress conditions and larger than the initial value under constant volume conditions. The proposed model provides a complementary method to conventional continuum dual-media approaches and provides a clear understanding of the interactions between the two components. Field-observed oscillatory gas production data is readily history-matched and key mechanisms explained with the proposed approach presented in this work. • A discrete model is built to define the interactions between inorganic minerals and organic matter in shale matrix. • The gas transport abilities in both components are defined as functions of gas pressure and effective strain. • A desorption-diffusion-seepage coupled experiment is used for verification and the flow rates are explained reasonable. • The proposed model gives a complementary way to the conventional continuous dual-media approach. • Field-observed oscillatory gas production data is readily history-matched and explained with the proposed approach. [ABSTRACT FROM AUTHOR]