Abandoned production and monitoring wells in depleted oil and gas fields can readily serve as primary leakage pathways for stored CO₂. The temperature, pressure conditions around the wellbore bottom, and CO₂ concentration influence the phase behavior of CO₂ during leakage. This study establishes a 3D wellbore–reservoir coupled model using CO₂ injection data from 1 December 2009, in the DAS area, eastern Cranfield oilfield, Mississippi, USA, to analyze the dynamic evolution of CO₂ leakage along wellbores. Simulations are conducted using the collaboration of ECO2M and ECO2N v2.0 modules. The study examines leakage regimes under varying distances from the injection well and different reservoir temperatures. The results indicate that CO₂ phase changes occur primarily in wells near the injection point or under high-pressure and high CO₂ saturation conditions, usually with a short leakage period due to ice formation at the wellhead. In areas with low CO₂ saturation, prolonged leakage periods lead to significant pressure drops at the bottom, as well as the temperature as a result of the Joule–Thomson effect. Lower reservoir temperatures facilitate smoother and more gradual leakage. These findings provide a theoretical foundation for ensuring the safe implementation of CCUS projects and offer insights into the mechanical explanation of CO₂ geyser phenomena.