Shale Nanopores Research Articles

Analytical simulation of the simultaneous adsorption process of methane and water vapor in shales

ABSTRACT Investigations on the diffusion – adsorption of methane and water vapour in shale nanopores are essential for developing shale gas extraction. A kinetic model considering diffusion and different adsorption mechanisms was proposed. An analytical solution to the model was obtained through the integral transformation method and used to predict the distributions of methane and water within a shale particle. The results suggest that the reversible adsorption caused by the dispersion force is not the only adsorption mechanism; irreversible adsorption caused by hydrogen bonding or other types of intermolecular forces is more prominent, lengthening the delay to reach equilibrium. The presence of water strongly affects shale, considerably decreasing the diffusivity and adsorption capacity as well as the swelling of the shale matrix caused by the increase in the methane pressure. The diffusion and adsorption process expands to the shale particle surface after the pores near the particle centre are filled. The transport and storage of water vapour are more sensitive to the pore structure than those of methane. In the initial stage of the methane diffusion‒adsorption process, a large number of water molecules enter the particles, and the adsorbed water hinders methane molecules from contacting the shale surface.

Effect of water distribution on methane-carbon dioxide-water transportation in shale nanopores with Knudsen number correction

The flow mechanism of a CO2-CH4-H2O system plays a key role in methane recovery and CO2 sequestration. In this paper, Knudsen number correction and water phase distribution are taken into account to establish a new transport model for the CO2-CH4-H2O flow in shale nanopores. The model is validated using data from three flow experiments, namely, methane-carbon dioxide flow experiments under dry conditions, methane with irreducible water flow characterization experiments in the nanofluidic chip, and air–water two-phase flow experiments in quartz sand. The effect of irreducible water on gas flow and methane-carbon dioxide-water relative permeability is discussed. The results in our paper show that: (1) The existence of irreducible water increases the difference caused by Knudsen number correction. (2) The existence of irreducible water has a negative effect on the gas flow in most cases. The reduction of methane and carbon dioxide permeability with irreducible water can be up to 28.53% and 21.88%, respectively. (3) The change of permeability curve is affected by gas composition fraction, water saturation, and irreducible water coverage. The study provides theoretical guidance for carbon dioxide enhancing shale gas recovery under the actual water saturation condition.

Imbibition mechanism of water in illite nanopores of deep shales by molecular simulation

Hydraulic fracturing is an important technique to develop deep shale gas. After hydraulic fracturing, a large amount of fracturing fluid fails to flow back and retains in deep shales. This phenomenon leads to fracturing fluid imbibition and significantly impacts on gas production. However, the understanding of imbibition mechanism in deep shales is very limited. In this work, the microscopic mechanism of fracturing fluid imbibition into illite pores of deep shales was studied using molecular simulation. The factors affecting imbibition were also analyzed. Results show that water imbibition in illite pores can be divided into three stages. In stage 1, the hydrogen bonds between water molecules and illite pore walls are formed, which forces water to enter the pores and becomes a water layer. In stage 2, the hydrogen bonds between water molecules and the water layer are formed, and gas begins to be displaced out of the pores by water. In stage 3, water molecules no longer enter the pores, and the system becomes equilibrium. As for the influencing factors, fugacity pressure mainly affects the imbibition time. The imbibition time becomes longer when fugacity pressure rises. Pore size plays a significant role in imbibition. Gas in illite pores can be totally displaced if the pore size is smaller than 5 nm. The imbibition is also affected by the amount of water. More gas tends to be displaced out of the pores when the ratio of water volume to pore volume (RWP) increases.

Molecular insights into dual competitive modes of CH4/CO2 in shale nanocomposites: Implications for CO2 sequestration and enhanced gas recovery in deep shale reservoirs

CO2 enhanced shale gas recovery has significant potential for improving the recovery rate of adsorbed gas and facilitating the geological sequestration of CO2. Nevertheless, the feasibility and microscopic mechanisms of CO2 enhanced gas recovery in deep shale gas reservoirs remain to be elucidated. In this study, a quartz-kerogen slit model was constructed to represent the shale composite nanopores of deep shale reservoirs. Utilizing the grand canonical Monte Carlo and molecular dynamics methods, the adsorption and diffusion behavior of CH4, CO2 and their mixtures was investigated under high-temperature and high-pressure conditions representative of deep shale reservoirs. The influences of temperature, pressure and aperture size were analyzed. The microscopic mechanisms governing the CH4/CO2 competitive adsorption in deep shale nanopores were uncovered by considering the competitive interactions between different rock constituents and quantifying the various gas storage states. The results show that the adsorption capacity of CO2 is greater than that of CH4 under the deep shale reservoir conditions. The replacement efficiency of CH4 by CO2 is higher in small shale pores. High temperature has a more significant negative impact on the adsorption of CO2 compared to that of CH4. Compared to mid-deep shale reservoirs, the nanopores of deep shale reservoirs have a higher proportion of free CH4/CO2 states. Quartz exhibits greater affinity for CH4/CO2 than kerogen, but kerogen possesses a larger specific surface area, resulting in a higher adsorption capacity per unit volume. The hierarchy of CH4/CO2 diffusion capacity in various storage states is as follows: dissolved gas in the kerogen matrix < adsorbed gas on the quartz surface < adsorbed gas on the kerogen surface < free gas in the pore center. This study improves the understanding of CO2 enhanced gas recovery in deep shale gas reservoirs.

Quantum physisorption behavior of methane in nanoporous shales: Model and new mechanism

Methane adsorption in nanoporous shales plays a significant role in the storage and flow of shale gas. Although previously numerous theoretical models have been proposed to describe the gas adsorption behavior, how the potential energy distribution in nanopores impacts gas adsorption remains unclear. The mechanism of methane adsorption in extremely complicated nanopores is still no satisfactory explanation. In this study, a total of 28 shale samples located in the Paleozoic-Mesozoic strata from different sedimentary environments were utilized to investigate the nature and process of quantum physisorption of methane in nanoporous shales. It was suggested that methane confined within nanoscale space shows a quantum effect, and the physisorption behavior of methane may be the result of molecular energy level transition. Further, the quantum physisorption model was developed by considering the quantum potential energy distribution, maximum adsorption amount, gas temperature and gas pressure, which matches the isothermal adsorption data well for a various of shales under widely varied temperature and gas pressure condition. The adsorption amounts of methane with different energy levels can also be obtained by the model. Finally, a new mechanism of the methane quantum physisorption in nanoporous shales was proposed. Uneven spatial distribution of gas molecules and elementary space of gas adsorption are the intrinsic factors of controlling the quantum physisorption behavior. The former is mainly influenced by minimum potential unit (E0) and gas temperature, while the latter is represented by the parameter of maximum adsorption amount (nL) which impacted by specific surface area and gas temperature. Gas pressure only affects the molecule concentration with different energy levels, but does not affect the spatial distribution of molecule. E0 and nL vary in shales from different sedimentary environments, due to the difference in organic matter properties (TOC content and kerogen type), which indirectly impacts the methane physisorption behavior. These results are helpful to deeply understand the storage of methane in shales and improve the efficient development of shale gas. In addition, this study is expected to open a new research direction about the quantum physisorption of gas in nanoporous media.

A comprehensive mathematical model considering multiple mechanisms for CO2 displacement of methane in shale nanopores

With the rise in energy demand, shale gas exploitation has gained prominence, particularly through the use of carbon dioxide (CO2) injection for enhanced gas recovery. However, the intricate gas flow mechanisms within this process in shale nano-pores remain poorly understood, which greatly limited the accurate numerical simulation of shale gas production by CO2 injection. This study investigates the flow mechanisms of CH4 and CO2 gases in shale nano-pores, developing an improved apparent relative permeability model for the two-component CH4–CO2 gas, incorporating multiple transport mechanisms. Sensitivity analysis includes factors such as pressure, pore radius, viscosity correction effects, flow mechanisms, and composition fractions. Key findings from this study are as follows: (1) Increasing pore radius or decreasing pressure enhances the apparent permeability of CH4–CO2 gas, with pressure effects becoming negligible above 20 MPa. (2) The impact of viscosity correction on gas permeability diminishes with higher pressure or larger pore radius, becoming negligible for pore radii over 10 nm. (3) Larger pore radii increase slip flow and Knudsen diffusion, while molecular and surface diffusion proportions decrease; surface diffusion and slip flow dominate at high pressures. (4) A higher CH4–CO2 component ratio increases CH4 permeability and decreases CO2 permeability, with minimal influence from pressure and pore radius. These results can improve numerical simulations for shale gas production by using CO2 injection.

In situ shale wettability regulation using hydrophobic ionic liquid functionalized nano-silica to enhance wellbore stability in deep well drilling

Shale wellbore instability due to hydration significantly hinders the efficient extraction of clean shale gas resources, making the development of effective shale stabilizers for safe drilling in shale reservoirs an urgent priority. In this study, we proposed an innovative application of hydrophobic ionic liquids functionalized nano-SiO2 (ILs@SiO2) specifically designed to maximize hold wellbore strength and effectively inhibit shale hydration. The chemical composition and microstructure of ILs@SiO2 were characterized, and their effects on wellbore stability were thoroughly investigated along with the underlying mechanisms. The shale stabilizer demonstrated significant clay swelling inhibition (9.5 %), as well as effective hydration and dispersion inhibition of shale cuttings at 150 °C (88.0 %), and a reduced spontaneous imbibition of shale (0.997 g). Particularly, ILs@SiO2 maximized maintained wellbore strength (203.4 MPa) and minimized water invasion (5.5 mL). Mechanism analysis revealed that ILs@SiO2 improved wellbore stability through electrostatic adsorption weakening osmotic hydration, physical plugging establishing a dense preventing water barrier, altering wettability decreasing rocks surface free energy, inhibiting surface hydration, and reversing the direction of capillary forces. This study offers new strategies and insights for constructing methods to plug shale nanopores and inhibit surface and osmotic hydration.

Depressurization-induced production of shale gas in organic-inorganic shale nanopores: A kinetic Monte Carlo simulation

Methane gas production from unconventional reservoirs, such as shale formations, is in high demand due to the global energy needs. However, maximizing production remains challenging due to the ultra-tight porosity, heterogeneity, and complex nature of shale rocks under high pressure. To address this issue, we employ a novel kinetic Monte Carlo (kMC) simulation to investigate the molecular-level behavior of shale gas in both homogeneous and heterogeneous organic-inorganic shale nanopores. This approach not only provides accurate computations of shale gas under high pressure but also aims to uncover the mechanisms of shale gas storage at reservoir pressure and production during pressure drawdown. Our findings indicate that organic shale ultramicropores (pore width < 0.7 nm) contribute significantly to the highest storage capacity of shale gas but pose challenges for production capacity solely through depressurization. In contrast, the free gas zone is the primary source of shale gas production from mesoporous shales, which has a high recovery efficiency but a low production capacity due to less pronounced interaction effects from the shale surface. The heterogeneous nature of shale surfaces leads to asymmetric distributions of density and potential energy across pore widths, with methane molecules favoring locations near organic pore walls due to stronger attractive interactions, while inorganic pore walls facilitate shale gas migration. Interestingly, the optimal ultramicropore size yields the highest recovery efficiency of shale gas via depressurization, characterized by a transition from near-commensurate to incommensurate molecular packing between reservoir and post-drawdown pressures. Based on these detailed molecular simulations, further research is necessary to develop innovative techniques for enhancing shale gas recovery, especially in micropores.

Influence of inherent mineral matrix on the geochemical reactions and pore structure evolution from shale oxidative dissolution

Oxidant stimulation presents a promising avenue for enhancing fluid mobility in shale reservoirs with ultra-low permeability and porosity. However, the effect of diverse minerals, major components of shale, on geochemical reactions and associated microstructures still warrants further exploration. In this study, we employed acid demineralization followed by oxidant stimulation to explore the impact of carbonate and silicate minerals on shale oxidative dissolution, considering both geochemical reactions and pore structures. Combined with artificial neural network (ANN) modeling, the dominance of shale composition on pore structures variation was further elucidated. Results demonstrated effective removal of carbonate and silicates minerals following treatment with HCl and HF acids. Interestingly, while silicate minerals exhibited greater mass loss in response to all oxidant stimulations, carbonate minerals only contributed to mass loss induced by Na2S2O8. Integration of X-ray diffraction, Fourier transform infrared spectroscopy, water chemistry and total organic content analysis revealed mineral- and oxidant-dependent geochemical reactions within the stimulation process. These included preferential dissolution of K-feldspar, dedolomitization accompanied by different precipitates, and transformation from quartz to albite, among other conventional reactions. The alteration in mineral and organic matter composition also induced variation in shale nanopores structures, resulting in increased specific surface area, nanopore volume, and average pore diameter induced by acid treatment, while the effects of oxidants varied. To better understand the relationship between shale composition and micropore structure, an ANN model was established to quantify this underlying connection, emphasizing the significant role of carbonate, chlorite, pyrite, and organic matter in shale oxidative dissolution. Our study provides further evidence for the influence of minerals on shale oxidative dissolution, offering insights for the engineering application of oxidant stimulation in shale gas extraction.

Mathematical Model of the Migration of the CO2-Multicomponent Gases in the Inorganic Nanopores of Shale

Nanopores in shale reservoirs refer to extremely small pores within the shale rock, categorised into inorganic and organic nanopores. Due to the differences in the hydrophilicity of the pore walls, the gas migration mechanisms vary significantly between inorganic and organic nanopores. By considering the impact of irreducible water and the variations in effective migration pathways caused by pore pressure and by superimposing the weights of different migration mechanisms, a mathematical model for the migration of CO2-multicomponent gases in inorganic nanopores of shale reservoirs has been established. The aim is to accurately clarify the migration laws of multi-component gases in shale inorganic nanopores. Additionally, this paper analyses the contributions of different migration mechanisms and studies the effects of various factors, such as pore pressure, pore size, component ratios, stress deformation, and water film thickness, on the apparent permeability of the multi-component gases in shale inorganic nanopores. The research results show that at high pressure and large pore size (pore pressure greater than 10 MPa, pore size greater than 4 nm), slippage flow dominates, while at low pressure and small pore size (pore pressure less than 10 MPa, pore size less than 4 nm), Knudsen diffusion dominates. With the increase of the stress deformation coefficient, the apparent permeability of gas gradually decreases. When the stress deformation coefficient is less than 0.05 MPa−1, the component ratio significantly impacts bulk apparent permeability. However, when the coefficient exceeds 0.05 MPa−1, this influence becomes negligible. The research results provide a theoretical basis and technical support for accurately predicting shale gas productivity, enhancing shale gas recovery, and improving CO2 storage efficiency.

Molecular Insight into CO2 Improving Oil Mobility in Shale Inorganic Nanopores Containing Water Films.

CO2 injection into shale reservoirs has been recognized as one of the most promising techniques for enhanced oil recovery and carbon capture, utilization, and storage. However, the omnipresent nanopores and the water films formed near the pore walls affect the understanding of mechanisms of CO2 regulating crude oil mobility in shale nanopores. In this work, we employ molecular dynamics simulations to study the occurrence and flow of CO2 and octane (nC8) mixtures in quartz nanopores containing water films, to illustrate the impact mechanisms of CO2 on nC8 mobility. The results indicate that nC8 exists between water films, and CO2 is mainly miscible with nC8 in the pore center, and a small portion of it accumulates at the interface between nC8 and the water film. CO2 significantly decreases the apparent viscosity of nC8 in both the bulk nC8 region and the nC8-water interface region, improving nC8 fluidity. As the percentage of CO2 in the CO2 and nC8 mixtures increases from 0 to 50%, the mean flow velocities of nC8 in the bulk phase region and the nC8-water interface region increase by 92.85 and 60.64%, respectively. Three major microscopic mechanisms of CO2 improving nC8 fluidity in quartz nanopores with water films are summarized: (i) CO2 reduces friction between nC8 and the water film by increasing the angle between nC8 molecules and the plane of the water film; (ii) CO2 widens the distance between nC8 molecules, causing the volume expansion of nC8 and its viscosity reduction; (iii) CO2 significantly increases the most probable and average velocities of nC8 molecules, thus improving their mobility. Our results enhance the comprehension of how CO2 facilitates oil flow in water-bearing shale reservoirs and the exploitation of unconventional oil resources.

Molecular simulation of the competitive adsorption of methane and carbon dioxide in the matrix and slit model of shale kerogen and the influence of water

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

Methane-Water Interfacial Tension in Nanopores: A Dissipative Particle Dynamics Study.

Imbibition of fracturing fluid in deep shale nanopores has a significant effect on shale gas production. One of the key parameters affecting imbibition is the interfacial tension of the methane-water system. However, studies on the methane-water interfacial tension in nanopores are very limited, and obtaining the accurate value of the methane-water interfacial tension at the nanoscale is difficult and time-consuming. In this work, a dissipative particle dynamics simulation model was built to study the methane-water interfacial tension in nanopores. This model provides reliable access to methane-water interfacial tension for deep shales under high-temperature, high-pressure conditions at low computation cost. It can be easily used to compute the methane-water interfacial tension in nanopores or the confined space in wide application scenarios. A sensitivity study of methane-water interfacial tension on a variety of factors was conducted. Results demonstrate that under high-pressure conditions, the increase in pressure leads to the rise of interfacial tension. When pressure increases from 20 to 120 MPa, interfacial tension rises from 0.0275 to 0.12 N/m, which contributes to the severe imbibition of fracturing fluid in deep shales. The confinement effect was observed by investigating the influence of pore size. Interfacial tension almost remains unchanged in pores smaller than 7 nm because most of the confined space is occupied by interface layer molecules in these pores. When pore size increases from 7 to 15 nm, the confinement effect is reduced. The interfacial tension experiences a growth from 0.1155 to 0.27 mN/m. Compared with pressure and pore size, the effect of temperature on interfacial tension can be neglected during deep shale gas production.

Scale translation yields insights into gas adsorption under nanoconfinement

This work describes a scale-translating simulation framework to investigate gas adsorption behavior in nanoconfined pores. The framework combines molecular simulations (MSs), equation of state (EoS), and lattice Boltzmann (LB) simulations. MSs reveal the physics of methane adsorption in nano-sized pores, where input values of fugacity coefficients are optimized based on EoS predictions. Then, an LB free-energy model, which incorporates a viral EoS, upscales intermolecular forces and estimates adsorption behavior via a proposed fluid–wall interaction model. Armed with the values of the LB interaction parameter as a function of pressure, the LB model is used to predict fluid behavior in irregular nanopores, and the results are validated against reference MS data. The LB model is then used to study adsorption behavior at a continuum scale in representative organic shale nanopores based on finely characterized Vaca Muerta shale samples. The results show that methane adsorption could significantly increase contained fluids by 10%–25% in pores smaller than 20 nm. However, in larger pores (40 nm to 90 nm), adsorption's impact diminishes to 2%–3%, suggesting sorption's negligible role beyond a 40 nm pore size.

Giant Effect of CO2 Injection on Multiphase Fluid Adsorption and Shale Gas Production: Evidence from Molecular Dynamics.

Carbon dioxide (CO2) injection in unconventional gas-bearing shale reservoirs is a promising method for enhancing methane recovery efficiency and mitigating greenhouse gas emissions. The majority of methane is adsorbed within the micropores and nanopores (≤50 nm) of shale, which possess extensive surface areas and abundant adsorption sites for the sequestration system. To comprehensively discover the underlying mechanism of enhanced gas recovery (EGR) through CO2 injection, molecular dynamics (MD) provides a promising way for establishing the shale models to address the multiphase, multicomponent fluid flow behaviors in shale nanopores. This study proposes an innovative method for building a more practical shale matrix model that approaches natural underground environments. The grand canonical Monte Carlo (GCMC) method elucidates gas adsorption and sequestration processes in shale gas reservoirs under various subsurface conditions. The findings reveal that previously overlooked pore slits have a significant impact on both gas adsorption and recovery efficiency. Based on the simulation comparisons of absolute and excess uptakes inside the kerogen matrix and the shale slits, it demonstrates that nanopores within the kerogen matrix dominate the gas adsorption while slits dominate the gas storage. Regarding multiphase, multicomponent fluid flow in shale nanopores, moisture negatively influences gas adsorption and carbon storage while promoting methane recovery efficiency by CO2 injection. Additionally, saline solution and ethane further impede gas adsorption while facilitating displacement. Overall, this work elucidates the substantial effect of CO2 injection on fluid transport in shale formations and advances the comprehensive understanding of microscopic gas flow and recovery mechanisms with atomic precision for low-carbon energy development.

Competitive adsorption of CH4/CO2 in shale nanopores during static and displacement process

During the development of shale gas, various issues such as low individual well production, rapid decline, limited reservoir control, and low recovery rates have arisen. Enhancing shale gas reservoir recovery rates has consistently been a focal point and challenge within the industry. Therefore, this paper employs molecular dynamic (MD) simulation methods to study the adsorption and diffusion characteristics of CH4/CO2 at different temperatures and mixing ratios. It compares the effects of temperature and CH4/CO2 molar ratio changes on the selectivity coefficient, adsorption capacity, and diffusion coefficient of CH4/CO2. The paper also plots the displacement interface and the function of CH4/CO2 injection/residual amounts over time. Furthermore, it analyzes the adsorption capacity of molecules on the graphene surface, the migration capacity of molecules in the slit, and the displacement process of CH4 by CO2 on the nanoscale, revealing the microscopic mechanism of CH4/CO2 competitive adsorption and displacement. The research results indicate that the influence of temperature on the selectivity coefficient is not significant, with an average decrease of 3% for every 20 K rise in temperature. Pressure has a more pronounced effect on the selectivity coefficient, with values around 1.4 at low pressures and around 1.2 at high pressures. Elevating the mole fraction of CO2 in the binary gas mixture results in an increase in the total adsorption amount and an accelerated variation of adsorption amount with pressure. As the CH4 mole fraction rises, the diffusion coefficient of CH4 increases, while the diffusion coefficient of CO2 diminishes with an increasing CO2 mole fraction. Under identical conditions, CO2 exhibits a stronger adsorption capacity over CH4 in shale organic nanopores, resulting in a concave moon-shaped displacement interface in the model. The larger the pre-adsorption pressure of CO2, the more intense the movement of CO2 along the graphene surface, and the faster the diffusion speed of CO2 along the wall. In a displacement pore (the pore space used to provide the displacement location or site) with a diameter of 3 nm, at smaller pressure differentials (≤10 MPa), the residual amount of CH4 remains relatively stable without substantial alteration. However, at a pressure differential of 20 MPa, the residual amount of CH4 decreases rapidly, and the displacement efficiency significantly improves.

Competitive adsorption mechanisms of multicomponent gases in kaolinite under electric fields: A molecular perspective

The investigation of the competitive adsorption mechanisms of gas mixtures within the inorganic nanopores of shale influenced by an electric field holds paramount importance for improving shale gas recovery and enhancing CO2 storage efficiency. This study employs molecular dynamics (MD) simulations to investigate the competitive adsorption mechanisms of gas mixtures on kaolinite surfaces. Subsequently, the engineering parameters governing electric field-enhanced CO2 sequestration and enhanced gas recovery (CS-EGR) are explored and optimized. In the absence of an electric field, the analysis reveals that water molecules exhibit the highest adsorption capacity in a ternary H2O–CO2–CH4 mixture, resulting in the formation of a water film of a specific thickness. CO2 displays a superior adsorption capability over CH4. As the CO2 volume injected into the reservoir increases, CH4 undergoes desorption due to the dominant adsorption effect of CO2. However, the efficiency of CO2 displacing CH4 diminishes significantly. The introduction of an electric field alters the equilibrium state of the gas mixture, leading to a further increase in CO2 adsorption and enhancing its selectivity relative to that of CH4 by 33%. These findings lay the foundation for the practical implementation of electric field-enhanced CS-EGR in shale reservoirs.

Mechanisms of carbon dioxide extracting oil at the boundary layer on shale nanopore surface: insights from molecular dynamics

Boundary layer formed by crude oil on the shale nanopores surface hinders fluidity of crude oil and leads to a decline in oil recovery. CO2 injection has been considered as an effective method to enhance shale oil recovery. However, the impact of CO2 on the disruption of boundary layers within shale nanopores and the extraction mechanisms of crude oil during the recovery process remains unclear. In this work, molecular dynamics simulation was employed to investigate the process of using scCO2 to extract crude oil from shale nanopore surface. During the process of scCO2 extraction, polar molecules have the capability to reduce the diffusion coefficient, prolong the residence time, and decrease flowability of decane, ultimately resulting in a deterioration of its kinetic properties. Phenol, with its hydrophilic hydroxyl group, closely adheres to the shale surface, while the oleophylic benzene ring covers the shale surface, causing a transition in the wettability of this segment from hydrophilic to oleophylic. As a result, a substantial adsorption of decane occurs on phenol. The research findings contribute to the comprehension of the scCO2 extraction mechanism and the advancement of unconventional oil and gas resources.

Multicomponent image-based modeling of water flow in heterogeneous wet shale nanopores

Shale contains abundant multicomponent nanopores with different wettability. Water flow in multicomponent nanoporous systems is still unclear due to the effects of mineral composition, complex pore-throat topology, and heterogeneous wettability. This work develops a contact angle-dependent numerical model for nanoconfined water flow considering heterogeneous wettability, slip effect, and effective viscosity. Water flow in single-component (i.e., clay, organic, inorganic) and multicomponent nanoporous media reconstructed utilizing image fusion techniques is systematically investigated. Results show that the enhancement factor increases exponentially, and the tortuosity increases with increasing contact angle. Water flow is inhibited under strongly hydrophilic conditions, with the enhancement factor linearly negatively correlated with specific surface area. Under hydrophobic conditions, the throat aspect ratio is inversely related to the enhancement factor, which is suppressed in quasi-circular pores. Water flow is restricted in clay pores and enhanced in organic pores due to the differences in pore-throat size and wettability. For the heterogeneous wetting system, the global flow is enhanced compared to no slip and homogeneous wetting conditions. Affected by clay and organic pores with different wettability, the velocity is non-uniformly enhanced, and the effect diminishes as water flows. This work provides a numerical perspective for water flow in heterogeneous wet nanoporous systems.

Hydrocarbon Transportation in Heterogeneous Shale Pores by Molecular Dynamic Simulation.

Shale oil in China is widely distributed and has enormous resource potential. The pores of shale are at the nanoscale, and traditional research methods encounter difficulty in accurately describing the fluid flow mechanism, which has become a bottleneck restricting the industrial development of shale oil in China. To clarify the distribution and migration laws of fluid microstructure in shale nanopores, we constructed a heterogeneous inorganic composite shale model and explored the fluid behavior in different regions of heterogeneous surfaces. The results revealed the adsorption capacity for alkanes in the quartz region was stronger than that in the illite region. When the aperture was small, solid-liquid interactions dominated; as the aperture increased, the bulk fluid achieved a more uniform and higher flow rate. Under conditions of small aperture/low temperature/low pressure gradient, the quartz region maintained a negative slip boundary. Illite was more hydrophilic than quartz; when the water content was low, water molecules formed a "liquid film" on the illite surface, and the oil flux percentages in the illite and quartz regions were 87% and 99%, respectively. At 50% water content, the adsorbed water in the illite region reached saturation, the quartz region remained unsaturated, and the difference in the oil flux percentage of the two regions decreased. At 70% water content, the adsorbed water in the two regions reached a fully saturated state, and a layered structure of "water-two-phase region-water" was formed in the heterogeneous nanopore. This study is of great significance for understanding the occurrence characteristics and flow mechanism of shale oil within inorganic nanopores.