Abstract: To address the challenges of poor sweep efficiency of injected media and unpredictable fracture propagation behavior in traditional energy-replenishment development and fracturing stimulation for reservoirs characterized by water sensitivity, low-permeability, and strong heterogeneity, a three-dimensional fine reservoir numerical model with strong heterogeneity was established based on the Rarefed–Leap-frog (R-L) coupling method, and the degree of reservoir heterogeneity was quantified using indicators such as permeability contrast and porosity variation coefficient. By comparing the stimulation performance of hydraulic fracturing, CO₂-enhanced fracturing, and N₂ fracturing, and incorporating CO₂ dissolution effects, the influence patterns of geomechanics parameters on fracture propagation was clarified and the mechanism of CO₂-enhanced fracturing was determined. The results indicate that CO₂-enhanced fracturing exhibits optimal adaptability for such reservoirs, creating more complex fracture networks and yielding the maximum stimulated reservoir volume (SRV). However, CO₂ dissolution effects are predominantly negative: weakly acidic fluids induced by CO₂ dissolution aggravates clay mineral swelling, resulting in a significant near-wellbore permeability decline that partially offsets the positive energy-enhancement effects. A higher Young's modulus promotes longer fracture propagation, yet the incremental gain in SRV tends to slow down beyond a certain threshold. In contrast, a higher Poisson's ratio reduces SRV and simplifies fracture morphology. Numerical simulations specific to the target block further demonstrate that fractures propagate more easily in regions where Young's modulus is ≥18.75 GPa and Poisson's ratio is ≤0.22. Moreover, when the permeability ratio is ≥1.5 and the in-situ stress coefficient of variation is ≥0.25, SRV decreases by over 20%. These findings provide technical guidance for CO₂-enhanced fracturing operations in horizontal wells within analogous reservoirs.