Wellbore thermo-mechanical response during CO2 mixture geological sequestration in depleted reservoirs

The wellbore serves as a critical channel for fluid injection during CO₂ geological sequestration. Accurate prediction of wellbore injection fluid properties, temperature-pressure evolution, and tubing mechanical responses is essential for safe CO₂ storage in depleted wells. This study established a comprehensive model incorporating real-time variations in mixed gas physical and thermodynamic properties with corrections for high-pressure conditions. The model accounts for intermolecular forces, Joule-Thomson effects, and viscous heat sources, while coupling these with tubing mechanical changes to simulate wellbore evolution during CO₂ mixture injection. Model validation against field measurements demonstrated high reliability and accuracy. Using this model, we analyzed wellbore temperature-pressure and tubing mechanical evolution under various injection parameters for different gas mixtures (CO₂, N₂, O₂, CH₄) and examined tubing loads' impact on sealing performance. Results indicate that mixture compositions minimally affect wellbore temperature but significantly influence pressure and density. Higher CO₂ concentrations increase bottomhole pressures and fluid densities. Injection temperature substantially affects shallow sections, with high-temperature injection exhibiting temperature inversion. Injection pressure and rate significantly influence wellbore conditions and tubing forces. Early injection periods show pronounced effects that gradually stabilize. Analysis of sealing loads revealed that low-temperature injection compromises wellhead hanger performance, while high-temperature injection affects bottomhole packer integrity. These findings provide valuable guidance for optimizing CO2 mixture injection parameters and wellbore sealing performance.