Under the“carbon peaking and carbon neutrality”strategy，CO₂ flooding is regarded as a preferred approach to simultaneously enhance oil recovery and achieve geological storage in low-permeability reservoirs，yet its field performance often falls short of expectations. To clarify the spatiotemporal evolution mechanism of the oil-gas miscible zone during CO₂ flooding，physical simulation experiments of long-core CO₂ flooding were conducted and complemented with multi-scale numerical simulations. The study systematically characterized the differential propagation of miscible pressure fronts，phase fronts，and compositional fronts，as well as the dynamic evolution of the miscible zone during CO₂ flooding. Results show that，influenced by hydrocarbon component migration characteristics and multi-contact interactions，the miscible pressure front advances fastest，while the phase front lags behind the compositional front，leading to pronounced temporal and spatial variability in miscible zone distribution. Enhancing miscibility helps suppress the advance of the compositional front and delays the development of CO₂ breakthrough channels. Moreover，injection rate and volume exert significant regulatory effects on front propagation：when the injected CO₂ volume increases from 0.2 PV to 0.6 PV，the phase front extension reaches 68%，effectively broadening the miscible zone. However，excessive injection rates accelerate compositional front migration and aggravate gas channeling risks. Reservoir heterogeneity further complicates miscible zone distribution；when matrix permeability rises from 1.0 × 10^-3 μm² to 15.0 × 10^-3 μm²，the CO₂ phase sweep coefficient increases by 57.9%，whereas higher fracture permeability facilitates preferential compositional front migration through high-permeability pathways，resulting in uneven miscible zone distribution.