In carbon dioxide enhanced oil recovery and storage (CCUS) projects, sustained annular pressure is commonly attributed to packer sealing failure; however, pressure testing confirms the integrity of packer seals. This study proposes that this phenomenon arises from additional stress accumulation induced by temperature-pressure-phase coupling during CO₂ injection, leading to equivalent loads exceeding the packer’s sealing limit. By integrating the conservation laws of mass, energy, and momentum in fluid mechanics with the EXP-RK equation for phase behavior analysis, a coupled temperature-pressure-phase-stress multi-field model was developed to systematically quantify the synergistic effects of injection temperature, pressure, volume, and duration on wellbore stress fields. Validation using field data from a CO₂ injection well in the Changqing Oilfield demonstrated model accuracy, with a bottomhole pressure prediction error of 2.83% and temperature error of 1.75%, significantly outperforming conventional single-field models. Key findings include: (1) The injection temperature and injection volume are the main controlling factors for phase state evolution. The liquid-supercritical phase transition interface decreases significantly with the reduction of injection temperature and the increase of injection volume. (2) The injection temperature, pressure, and volume govern stress accumulation in the packer through thermal expansion, ballooning effects, and fluid friction. Critical threshold analysis revealed that equivalent loads exceed the unsealing limit (60 kN) when the target block meets any one of the following critical conditions: injection temperature≤6.5 ℃, pressure≥18.06 MPa, or volume≥2.61 t/h, causing packer unsealing.