Abstract: Taking the heavy oil reservoir in Block M of the Athabasca oil sands in Alberta, Canada, as an example, conventional Steam-Assisted Gravity Drainage (SAGD) technology faces issues such as severe heat loss and excessively high cumulative steam-to-oil ratio (cSOR). [Methods] This study employs the CMG-STARS numerical simulation method to compare three injection approaches: conventional SAGD, CO₂-steam co-injection, and CO₂-steam alternating injection. The analysis focuses on the steam chamber expansion characteristics, production dynamics, and CO₂ sequestration efficiency under different injection strategies. [Results] The results demonstrate that in the oil sands reservoir of Block M, CO₂-steam alternating injection facilitates the accumulation of CO₂ at the top of the steam chamber, forming an insulating layer that effectively suppresses gas channeling and reduces heat loss caused by steam override. This approach increases the steam chamber volume by 13.24%, achieving a final recovery factor of 80.61%, which is 33.38% higher than conventional SAGD and 40.35% higher than co-injection. Furthermore, compared to the gas injection rate, the injection pressure has a more significant impact on production enhancement. The optimal operational parameters were determined to be an injection pressure of 3.0 MPa and a gas injection rate of 250 m³/d. Further research confirms that CO₂-assisted SAGD achieves efficient CO₂ geological sequestration through multiple mechanisms, including dissolution trapping, residual gas trapping, and mineral trapping. After 20 years of post-injection shut-in, the vertical sweep of gaseous CO₂ is more extensive, with a more uniform spatial distribution, and the sequestration volume increases by 26.11% compared to the co-injection scenario. [Conclusion] This study provides fundamental theoretical guidance for enhancing oil sands SAGD production and CO₂ geological storage.