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The flow behavior and heat transfer characteristics of CO2in wellbores are crucial for its safe and efficient storage. Based on the classic Ramey wellbore heat transfer model, the prediction models of the temperature field and pressure field in the CO2gas mixture injection wellbore were established in this paper. The model comprehensively considers the interactions between different gas molecules, Joule–Thomson effects, and heat generation due to wall friction and improves the energy and momentum equations. Methods for calculating the physical properties of the gas mixture under both high- and low-pressure (below 10 MPa) conditions are provided. The specific heat capacity at constant pressure, density, and Joule–Thomson coefficient of the gas mixture are calculated using the modified BWRS equation with mixing rules. The viscosity of the gas mixture is determined by using the Lucas correlation. The total heat transfer coefficient is iteratively calculated using a thermal resistance model. By using these physical parameters, the temperature and pressure fields of the wellbore can be calculated. Compared with the experimental data, the accuracy of the model is verified. The calculation error of temperature and pressure at each node is kept within 3%, indicating that the accuracy of the model is improved. Based on the improved model, the changes of the temperature field and pressure field in the wellbore under different working conditions are analyzed when different gas mixtures (CO2, N2, and CH4) are injected. The results indicate that a change in the composition of the gas mixture has a minor impact on the temperature field but significantly affects the pressure field; higher CO2composition leads to increased bottom-hole pressure. The increase of the injection temperature and pressure both result in higher bottom-hole temperatures but have little effect on the pressure field. The pressure field reaches equilibrium faster than the temperature field. The research results can provide a reference for the migration law of gas mixture in the wellbore and the optimization of wellhead injection parameters.

Carbon capture, utilization, and storage (CCUS) is an important pathway that can effectively reduce CO2emissions, and the convective mixing phenomenon driven by a density difference in CO2brine reservoir storage is very important for long-term storage. In this study, the convective mixing process of CO2and brine under a series of reservoir conditions was investigated by high-pressure Hele-Shaw cell experiments and numerical simulations. The effects of pressure and salinity on the convective mixing characteristics were explored. The number of fingers increased to the peak and then decreased with small fluctuations. Then, the patterns of variation in dissolution concentration, dissolution rate, and density parameters over time were obtained. The density of the mixed solution and the concentration of dissolved CO2both increased with time. Higher pressure promotes convective mixing, and the increase in salinity rather inhibits the convective mixing to proceed. At a pressure of 8.5 MPa and a salinity of 10 g/L, the density difference as a driving force of convective mixing is the largest; therefore, the process is the fastest. Additionally, the numerical simulation modeled the convective mixing process and clearly showed the flow state of each fluid, with most of the fingers moving downward and the brine moving upward, with boundary effects affecting the fluid at the boundary. The numerical simulations also produced quantitative analysis results, which agreed with the experimental data. This study provides a more detailed understanding of the CO2convection mixing process under reservoir conditions, which has positive implications for the development of CCUS technology.

The technology of CO2-ESGR(CO2-enhanced shale gas recovery) is an effective means to practice energy saving and emission reduction and has drawn the attention of countries all over the world for its promising future. At present, the possibility and potential of the CO2-ESGR have been confirmed by some studies. However, the mechanism of shale gas occurrence is complex; existing studies have mainly focused on the static results of CH4displacement by CO2. Therefore, the dynamic process of CH4adsorbed in the shale being displaced by CO2was simulated in this study. The results show that the process of CH4displaced by CO2is divided into the CH4self-resolution phase, the displacement of residual CH4by CO2, and the stabilization phase. Moreover, the diffusion and desorption of CH4are less affected by pressure and pore size, and the effect of pressure and pore size on the diffusion and adsorption of CO2is more significant. The high pressure enhances the adsorption capacity between the pore wall and CO2, which can promote the effect of CH4displacement by CO2. In addition, another displacement phenomenon is derived in this study by examining the offset of the CO2and CH4density peak, in which CO2only occupies part of the CH4adsorption site and then both coexist for adsorption. This is different from the traditional theory that CO2displaces CH4by taking the place of it. It is conducive to revealing the dynamic mechanism of CO2displacing CH4. An in-depth study of the dynamic repulsion mechanism of CH4by CO2in geological rock formations can promote the application of the CO2-ESGR technology.

In this article, the diffusion of CO2in brine and saturated brine cores under offshore storage conditions was simulated by laboratory experiments. The diffusion coefficients of CO2to brine under the offshore storage temperature (286.15–303.15 K) and pressure (0.1–5 MPa) were obtained by using the pressure decay method, which are at a range of 0.126 × 10–9m2/s to 1.730 × 10–9m2/s. Meanwhile, the effective diffusion coefficients of CO2to saturated brine cores are measured through a system with computed tomography (CT) scanning characterization of three Berea cores with permeability from 10 to 100 mD, which are 1.22 × 10–15m2/s to 4.81 × 10–15m2/s at a pressure of 4 MPa and temperature of 290.15 K.