Interactions between injected CO2 and shale formation during the process of CO2 sequestration with enhancing shale gas recovery (CS-EGR) may alter the physical and chemical properties of the rock, affecting the efficiency of CO2 storage as well as CH4 production. To better understand these interaction-induced changes in shale properties, two shale samples selected from a marine Longmaxi formation and terrestrial Chang-7 member of the Yanchang formation were first reacted with supercritical CO2 (scCO2) in a laboratory batch reactor at 80 °C and 15 MPa with different time intervals, and then characterization methods were designed to access the geochemical changes including optical microscope (OM), X-ray diffraction (XRD), element analysis (EA), low-pressure gas adsorption (LPGA), and Fourier transform infrared spectroscopy (FTIR). The results indicate that the nanopore structure system of the two shale samples was significantly changed after scCO2–shale interaction due to the scCO2-induced extraction of hydrocarbons, chemical reactions in minerals, and the swelling effect in clay minerals as well as organic matter. However, after exposure to scCO2, the variation trend of pore structure parameters between the marine Longmaxi and terrestrial Chang-7 sample was quite different, which was related to the huge discrepancies in terms of mineralogy and geochemical properties between them. For marine Longmaxi sample, the pore surface area and pore volume obviously decreased after a relatively short period of scCO2 treatment, whereas an opposite trend was observed in a terrestrial Chang-7 sample after long-term scCO2 treatment. In addition, an obvious decrease in fractal dimensions for marine Longmaxi sample was also observed after scCO2 exposure, reflecting the degree of pore surface roughness, and pore structure complexity were reduced, whereas the terrestrial Chang-7 sample exhibited an opposite trend. The results contribute to the understanding of the potential factors for the pore-structure evolution during long-term CO2 storage and the possible effect on the CS-EGR process.

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Strong heterogeneity, low matrix permeability, and complex oil–water interaction make the fluid flow in carbonate rocks extremely complicated. In this study, we quantitatively characterize and simulate single-phase and multiphase flows with multiscale pore–vug–fracture structures involved in the carbonate reservoir developments. The main studies and conclusions include: (i) The CT technology is utilized to characterize the pores, fractures, and vugs of carbonate cores at multiple scales. It is found that even if the CT resolution reaches 0.5 μm, the pores of the core are still unconnected as a network, indicating that the carbonate matrix is particularly tight. The existence of fractures can increase the effective permeability, and even poorly connected fractures can significantly increase the permeability because it reduces the flow distance through the less permeable matrix. (ii) A numerical model of low-porosity strongly heterogeneous carbonate rocks was constructed based on digital image processing. Simulations of single-phase fluid flow under reservoir conditions were conducted, and the effects of surrounding pressure, pore pressure, and core size on the single-phase flow were investigated. Due to the strong heterogeneity of carbonate rocks, the pores, vugs, and fractures cause local preferential flow and disturbance within the core, which significantly affects the fluid flow path and the pressure distribution in the core. The overall permeability is a composite representation of the permeability of numerous microelements in the specimen. Permeability increases with an increasing pore pressure, and it decreases with increasing circumferential pressure. (iii) The gas–water two-phase flow model of a low-porosity strongly heterogeneous carbonate rock was established based on digital image processing. The variation law of the two-phase outlet flow velocity with the inlet gas pressure and the movement law of the two-phase interface of carbonate rock samples were obtained. Under certain surrounding pressure, the outlet gas velocity is larger than the outlet water velocity; with the increase of the inlet gas pressure, the pore space occupied by the gas phase in the rock becomes larger. With the increase of the surrounding pressure, the velocities of both outlet gas and water decrease. As the sample size decreases, the velocities of both outlet gas and water increase.

Knowledge of shale pore structure characteristics is crucial to understand gas storage and seepage mechanisms. Organic matter (OM) pores are considered the most important pore type in shale, and one of the currently significant research questions focuses on the spatial distribution and connectivity of OM pores. To answer this question, typical OM‐rich siliceous shale samples from the Lower Silurian Longmaxi Formation were comprehensively investigated using focused ion beam scanning electron microscopy. A three‐dimensional model of the OM‐rich region of interest was segmented and reconstructed based on numerous two‐dimensional slices. The types of OM were found to control the development of organic pores, and OM pores including honeycomb‐shaped pores, spongy‐shaped pores, and slit‐like irregular pores are mainly formed in the pyrobitumen. The pore structure parameters of the OM‐rich ROI revealed that the pore size distribution of honeycomb‐shaped OM pores formed in the pyrobitumen was mainly distributed in the range of 10–50 and 80–100 nm, while the throat equivalent diameter distribution demonstrated a unimodal curve with the main peak located at approximately 30 nm. Pore connectivity analysis further indicated that pyrobitumen also contained several isolated nano‐pores, and pores with diameters smaller than 40 nm were poorly connected. Furthermore, permeability simulation revealed clear discrepancies in different directions owing to the heterogeneity of the OM pores. These findings provide experimental evidence for the assessment of shale gas resources and their development potential.

The storage of carbon dioxide by injecting carbon dioxide into gas reservoirs has become an important technique for achieving carbon capture, utilization, and storage. However, most studies have focused on tight gas reservoirs, and there are still few studies on the injection of carbon dioxide into water-bearing gas reservoirs. This paper analyzes the variation of reservoir pressure during CO2 injection and points out the optimal amount of CO2 injection in the reservoir, which can provide theoretical guidance in practical applications. The relationship is plotted between the formation pressure and the volume of injected carbon dioxide. The effects of reservoir inhomogeneity and the water content on the formation pressure are discussed. Dynamic monitoring of the formation pressure during carbon dioxide injection is achieved. The optimal volume of injected carbon dioxide for water-bearing gas reservoirs is determined. The results show that the formation pressure increases with an increase in the volume of injected carbon dioxide, and the curve exhibits a trend of steep increases at both ends and a gentle increase in the middle. Enhanced reservoir inhomogeneity and a low reservoir water content are favorable for carbon dioxide injection.