Abstract: During CO₂ flooding or geological sequestration, the evolution characteristics of wellbore temperature and pressure directly affect the mechanical behavior of the pipe string. Based on thermo-mechanical coupling theory, a model for wellbore temperature & pressure field prediction and mechanical response of the pipe string during conversion to CO₂ gas mixture injection in mature wells was established. This model considers factors such as the dynamic variation of thermophysical parameters of the gas mixture, intermolecular interactions, the Joule–Thomson effect, and frictional heat sources. Model calculations show good match with the measured data, with average relative errors of 1.92% for temperature, 2.80% for pressure, and 3.98% for axial force of pipe string. The results indicate that variations in the composition of the gas mixture have a limited influence on the distributions of wellbore temperature and tubing axial stress, but significantly affect the distributions of wellbore pressure and mixed-fluid density. Injection temperature mainly affects wellbore temperature and gas density in the shallow section and may induce temperature inversion; high-temperature injection tends to increase the risk of packer sealing failure, whereas low-temperature injection is unfavorable to the sealing performance of the tubing hanger. Injection pressure and injection rate have significant effects on all investigated parameters. Injection duration predominantly influences the thermo–mechanical response during the early injection stage, while the relevant parameters gradually stabilize with prolonged injection time. The findings provide a theoretical basis for predicting the wellbore temperature and pressure fields and analyzing the mechanical response of the pipe string during conversion to CO₂ gas mixture injection in mature wells and offer guidance for subsequent studies on wellbore sealing safety evaluation.