Adsorption is one of the most important forms of storage of gas in shale reservoirs. Shale gas adsorption in the actual reservoir is not only affected by individual factors such as water content, temperature, and pressure but also by the synergetic effect of these factors. In this study, we conducted laboratory experiments on methane adsorption in dry and wet shale at different pressures and temperatures. The synergetic effect of water content, temperature, and pressure on shale gas adsorption is explored. The results show that increasing temperature weakens the interaction between methane and shale and reduces adsorption capacity due to the exothermic nature of adsorption. Water reduces methane adsorption capacity by occupying adsorption sites and blocking pores in the shale system. Although temperature and water reduce methane adsorption individually, the effect of these two factors weakens each other. Temperature has a more significant effect on methane adsorption in shales with low water content, while water has a more remarkable impact on methane adsorption at a low temperature. Furthermore, the increase in pressure reduces the negative influence of water and temperature on methane adsorption. By quantitatively analyzing the relationship between methane adsorption in dry and wet shales, a predictive adsorption model for wet shale considering the influence of in situ conditions is proposed and validated. Validation shows that the proposed model has high accuracy and broad applicability to shales with different properties.

Experimental investigation of methane adsorption and desorption in water-bearing shale

Low-permeability reservoirs have poor reservoir properties and are difficult to develop by conventional water flooding. CO₂ flooding can significantly improve oil recovery while achieving carbon storage, and is widely recognized as an effective solution for the development of low-permeability oil reservoirs. In order to address the lack of a comparative quantitative analysis of the tradeoff between oil recovery factor, CO₂ storage rate, and total CO₂ storage volume for the main injection modes in low-permeability reservoirs, this study systematically evaluated the performance of CO₂-enhanced oil recovery (EOR) and geological storage under different pressures and injection modes through core flooding experiments. The results indicate that displacement pressure and injection strategy significantly influence the CO₂ flooding performance. Continuous miscible flooding (30 MPa) substantially reduced the displacement pressure differential (maximum 6.1 MPa) and achieved the highest oil recovery (78.96%) and the greatest CO₂ storage capacity (5916 cm³). Miscible WAG flooding effectively delayed gas breakthrough (extended to 1.90 pore volumes), homogenized the displacement front, and yielded the best overall outcome: the highest ultimate oil recovery (83.8%) coupled with the optimal CO₂ storage rate (89.1%). The study further reveals that the pre-breakthrough stage is critical for contributing to oil recovery and achieving efficient storage, regardless of the injection modes. These findings clarify the technical characteristics and applicable conditions of different injection modes, providing crucial theoretical insights and practical guidance for optimizing CO₂ EOR and storage projects in low-permeability reservoirs.