Confinement Effects and CO2/CH4 Competitive Adsorption in Realistic Shale Kerogen Nanopores

Review of Competitive Adsorption of CO2/CH4 in Shale: Implications for CO2 Sequestration and Enhancing Shale Gas Recovery

The injection of CO2 into shale gas reservoirs can not only enhance shale gas recovery (ESGR), but also realize CO2 geological storage (CGS). In this study, the competitive adsorption behaviors of CO2 and CH4 in shale were systematically reviewed, and the implication for shale gas recovery efficiency and CO2 storage potential were discussed. The adsorption advantage of shale for CO2 compared to CH4 provides a guarantee of the feasibility of supercritical CO2 (ScCO2) enhanced shale gas exploitation technology. The selective adsorption coefficient of CO2 and CH4 by shale (S CO2/CH4 ) is an important parameter in evaluating the competitive adsorption behavior of CO2/CH4 in shale gas reservoirs, which is closely related to the mineral composition, reservoir temperature, pressure conditions, water content, and mixed gas composition ratio. In addition, the injection type, injection mode, and injection rate of gases also exhibit different effects on CO2/CH4 competitive adsorption. Furthermore, the interaction between ScCO2 and the water-rock system will change the mineral composition and microstructure of shale, which will lead to changes in the adsorption behavior of shale on CO2 and CH4, so its influence on the competitive adsorption of CO2/CH4 cannot be ignored. Future research should integrate different research methods and combine with practical engineering to reveal the competitive adsorption mechanism of CO2/CH4 in shale reservoirs from both micro and macro aspects. This study can provide support for the integration technology of ScCO2 enhanced shale gas exploitation and its geological storage.

A Review of Molecular Models for Gas Adsorption in Shale Nanopores and Experimental Characterization of Shale Properties

Shale gas, as a promising alternative energy source, has received considerable attention because of its broad resource base and wide distribution. The establishment of shale models that can accurately describe the composition and structure of shale is essential to perform molecular simulations of gas adsorption in shale reservoirs. This Review provides an overview of shale models, which include organic matter models, inorganic mineral models, and composite shale models. Molecular simulations of gas adsorption performed on these models are also reviewed to provide a more comprehensive understanding of the behaviors and mechanisms of gas adsorption on shales. To accurately understand the gas adsorption behaviors in shale reservoirs, it is necessary to be aware of the pore structure characteristics of shale reservoirs. Thus, we also present experimental studies on shale microstructure analysis, including direct imaging methods and indirect measurements. The advantages, disadvantages, and applications of these methods are also well summarized. This Review is useful for understanding molecular models of gas adsorption in shales and provides guidance for selecting experimental characterization of shale structure and composition.

Multiscale modeling of gas flow behaviors in nanoporous shale matrix considering multiple transport mechanisms

This study proposes a multiscale model combining molecular simulation and the lattice Boltzmann method (LBM) to explore gas flow behaviors with multiple transport mechanisms in nanoporous media of shale matrix. The gas adsorption characteristics in shale nanopores are first investigated by molecular simulations, which are then integrated and upscaled into the LBM model through a local adsorption density parameter. In order to adapt to high Knudsen number and nanoporous shale matrix, a multiple-relaxation-time pore-scale LBM model with a regularization procedure is developed. The combination of bounce-back and full diffusive boundary condition is adopted to take account of gas slippage and surface diffusion induced by gas adsorption. Molecular simulation results at the atomic scale show that gas adsorption behaviors are greatly affected by the pressure and pore size of the shale organic nanopore. At the pore scale, the gas transport behaviors with multiple transport mechanisms in nanoporous shale matrix are explored by the developed multiscale model. Simulation results indicate that pressure exhibits more significant influences on the transport behaviors of shale gas than temperature does. Compared with porosity, the average pore size of nanoporous shale matrix plays a more significant role in determining the apparent permeability of gas transport. The roles of the gas adsorption layer and surface diffusion in shale gas transport are discussed. It is observed that under low pressure, the gas adsorption layer has a positive influence on gas transport in shale matrix due to the strong surface diffusion effect. The nanoporous structure with the anisotropy characteristic parallel to the flow direction can enhance gas transport in shale matrix. The obtained results may provide underlying and comprehensive understanding of gas flow behaviors considering multiple transport mechanisms in shale matrix. Also, the proposed multiscale model can be considered as a powerful tool to invesigate the multiscale and multiphysical flow behaviors in porous media.

Heterogeneous Transport of Free CH4 and Free CO2 in Dual-Porosity Media Controlled by Anisotropic In Situ Stress during Shale Gas Production by CO2 Flooding: Implications for CO2 Geological Storage and Utilization

Regarding shale gas production by CO₂ flooding, few existing reports explain the performance of free CH₄ and free CO₂ in shale reservoirs controlled by anisotropic in situ stress, partly restricting the integrated recognition of shale-based CO₂ geological storage and utilization (CGSU). In this work, a self-developed model embedded with thermo-hydro-mechanical coupling relationships is introduced to investigate how the anisotropic in situ stress determines the transport of free gases (CH₄ and CO₂) after CO₂ is injected into the shale. Therefore, the stronger anisotropy of in situ stress enables more CO₂ in the free phase to be trapped in the shale reservoir and is insignificant for the content of residual free CH₄ compared to the situation under isotropic in situ stress. Along with CO₂ injection into the shale, the matrix porosity decreases invariably, while the fracture porosity decreases first and then increases gradually. Therein, the variation amplitude of the matrix/fracture porosity is more distinct under a stronger anisotropic in situ stress. The simulations also suggest that the ratio of free CO₂ relative to all free gases in shale is ∼65% at most after sufficient CGSU operation. Hopefully, this comprehensive work is helpful in enhancing the knowledge on the promising shale-based low-carbon CGSU technique.

Geochemical controls on CO2 interactions with deep subsurface shales: implications for geologic carbon sequestration

One of the primary drivers of global warming is the exponential increase in CO₂ emissions. According to IPCC, if the CO₂ emissions continue to increase at the current rate, global warming is likely to increase by 1.5 °C, above pre-industrial levels, between the years 2030 and 2052. Efficient and sustainable geologic CO₂ sequestration (GCS) offers one plausible solution for reducing CO₂ levels. The impermeable shale formations have traditionally served as good seals for reservoirs in which CO₂ has been injected for GCS. The rapid development of subsurface organic-rich shales for hydrocarbon recovery has opened up the possibility of utilizing these hydraulically fractured shale reservoirs as potential target reservoirs for GCS. However, to evaluate the GCS potential of different types of shales, we need to better understand the geochemical reactions at CO₂-fluid-shale interfaces and how they affect the flow and CO₂ storage permanence. In this review, we discuss the current state of knowledge on the interactions of CO₂ with shale fluids, minerals, and organic matter, and the impact of parameters such as pressure, temperature, and moisture content on these interactions. We also discuss the potential of using CO₂ as an alternate fracturing fluid, its role in enhanced shale gas recovery, and different geochemical tracers to identify whether CO₂ or brine migration occurred along a particular fluid transport pathway. Additionally, this review highlights the need for future studies to focus on determining (1) the contribution of CO₂ solubility and the impact of formation water chemistry on GCS, (2) the rates of dissolution/precipitation and sorption reactions, (3) the role of mineralogical and structural heterogeneities in shale, (4) differences in reaction mechanisms/rates between gaseous CO₂vs. brine mixed CO₂vs. supercritical CO₂, (5) the use of CO₂ as a fracturing fluid and its proppant carrying capacity and (6) the role of CO₂ in enhanced hydrocarbon recovery.

Different Effect Mechanisms of Supercritical CO2 on the Shale Microscopic Structure

To better understand how supercritical carbon dioxide (CO₂) enhances shale gas production, it is necessary to study the interaction of supercritical CO₂ with shale and its impact on shale microstructure. The different mechanisms by which supercritical CO₂ changes the shale pore structure were studied by X-ray diffraction analyses, scanning electron microscopy (SEM), nuclear magnetic resonance spectroscopy, and low-pressure nitrogen gas adsorption tests on shale samples before and after treatment with different pressures and gases (CO₂ and Ar). The results showed that after treatment with CO₂, the mineral content of shale changed significantly, and in particular, the proportions of calcite and dolomite decreased. The mineral content of shale changed the most after treatment with supercritical CO₂, and the microscopic pores were most observable by SEM. In a gaseous CO₂ environment, the effect of CO₂ adsorption on shale pores is greater than the effects of gas pressure and dissolution reactions. However, in a supercritical CO₂ environment, the changes in shale pore structures are mainly controlled by extraction and dissolution reactions. When shale is exposed to supercritical CO₂, the fractal dimensions of adsorption pores and seepage pores decrease, indicating that the specific surface area and roughness of adsorption pores decrease. This implies that the adsorption capacity decreases, and that the complexity of the seepage pores declines, which is conducive for gas migration.