The geometry and topology of shale pore-fracture systems govern hydrocarbon migration and control the feasibility of geological carbon dioxide storage in shale reservoirs. This study examines lacustrine shale across a range of maturities by integrating (ultra) small-angle neutron scattering, repeated mercury intrusion capillary pressure, field-emission scanning electron microscopy, and computed tomography following Wood’s metal impregnation. The pore system is divided into four pore-size classes, and their volumes and connectivity are tracked with increasing thermal maturity. At low maturity, mechanical compaction and early cementation reduce the total pore volume and concentrate connected porosity in fractures. As maturity increases, newly formed organic-matter pores lead to a modest increase in total pore volume, while liquid hydrocarbons generated within the oil window occupy part of the pore space and weaken pore-fracture connectivity. At high maturity, the secondary cracking of liquid hydrocarbons to gas raises pore pressure, partially reopens previously sealed pores and fractures, and enhances both total pore volume and pore-fracture connectivity. These results indicate that mature to high-mature lacustrine shales provide more pore surface area, storage space, and connected pathways for the long-term storage of carbon dioxide than low-maturity shales.

CO₂ injection in shale oil reservoirs has emerged as a promising technique for simultaneously achieving CO₂ geological storage and enhancing shale oil recovery. This study investigates the potential of CO₂ injection into shale oil reservoirs with natural fractures for carbon storage and enhanced oil recovery through a combination of experimental and numerical simulations. It focuses on the synergistic effects on carbon storage capacity and oil recovery efficiency. A series of CO₂ injection experiments using online NMR T₂ and stratified T₂ technology were conducted to validate the feasibility of carbon storage and oil recovery in shale oil reservoirs. The shale samples consist of three distinct pore space systems: kerogen, inorganic matrix, and shale bedding fractures. A coupled multiscale-multiphase simulation model was developed to facilitate a comprehensive analysis of the underlying mechanisms. In the model, kerogen, inorganic matrix, and shale bedding fractures are defined as triple-continuum media. The model integrates the mechanisms of molecular diffusion, adsorption, and viscous flow to accurately represent the mass transport processes during CO₂ injection in shale oil reservoirs. Within this framework, a series of mass transport partial differential equations were derived to describe the CO₂ injection process. The finite element method was used to numerically solve these equations, and the proposed model was validated against experimental results. Sensitivity analyses yielded the following results: (1) The shale bedding fractures are not only key reservoir spaces for shale oil but also the key mass transfer channels for shale oil and CO₂ during CO₂ injection. Increasing the permeability of the shale bedding fractures can significantly improve oil recovery efficiency and CO₂ adsorption amount. (2) The kerogen content and organic porosity have a significant impact on CO₂ adsorption amount and shale oil recovery factor, respectively. (3) High production pressure is essential for maximizing carbon storage capacity. Simultaneously, increasing injection pressure can effectively enhance carbon storage and shale oil recovery.

Shale gas has become increasingly significant in the global energy supply. Mineral heterogeneity in shales importantly impacts gas transport within the shale matrix and therefore the depletion history curve. A microscale discrete coupling model is introduced to clarify mass transfer and mechanical interactions, as well as their impact on gas transport properties, ranging from individual mineral through ensemble field scale. The model uses a mineral morphology thin-section obtained through tescan integrated mineral analyzer with the mechanical parameters, controlling both elastic and viscosity behavior of each mineral, achieved through nanoindentation. A coupled model for poromechanical evolution is proposed and solved using COMSOL. The applicability of the model results are validated against field data using a dimensionless approach. This confirms that in the early stages of gas depletion, gas is primarily liberated from inorganic minerals, whereas in later stages, it is predominantly sourced from adsorbed gas from the organic matter. Over time, the permeability of the inorganic minerals decreases, and a higher Young’s modulus of the minerals results in a greater ultimate permeability ratio. Evolution of the effective diffusion coefficient for the organic matter is controlled by multiple components. A negative correlation exists between mineral grain size and the creep effects, indicating that larger grain sizes result in smaller creep magnitudes during gas production. The Young’s modulus of inorganic matter is inversely correlated with the diffusion coefficient, while an increase in the Young’s modulus in the organic matter corresponds to a higher diffusion coefficient. The proposed model complements the traditional continuum dual-medium method and provides a clearer understanding of the interactions between minerals during gas depletion behavior.