To understand the pore-scale processes of asphaltene deposition during heavy oil recovery by CO2 flooding, a series of microscopic flooding experiments were conducted in two-dimensional models under high-temperature (80 degrees C) and high-pressure (2, 6, and 10 MPa) conditions. Two different heavy oils, AZ-4 and KD-9 (with viscosities of 7754 and 19 290 mPa.s, respectively, at 80 degrees C), were used. In these samples, up to 95% and 85% of oil viscosity reduction, respectively, could be achieved by CO2 dissolution. During CO2 flooding in the microscopic models, with increasing fluid pressure (6 and 10 MPa) and CO2 concentrations (60-80 mol %), bo(t)h the covered area (17-38%) and the sizes of the deposited particles (up to 200 mu m) became larger. At 6 MPa, a dynamic between between dissolution and precipitation was observed in large pores (with diameters of >350 mu m). According to the solvent dissolution test (heptane and toluene), the deposited solids comprise both asphaltene and alkane components. Between AZ-4 and KD-9, higher resin/asphaltene ratios tend to reduce asphaltene deposition during the dissolution of CO2 by stabilizing the solubility of asphaltene in crude oil. In addition, although permeability decreased (up to 15%) with increasing pressure (210 MPa) and CO2 concentrations (2570 mol %), the oil recovery mostly increased (up to 88.6% with AZ-4). The only decrease in oil recovery occurred with KD-9, which decreased from 64.7% (6 MPa, with a CO2 concentration of 69.7%) to 56.1% under 10 MPa and considerably high CO2 concentrations (79.7 mol %). Compared with the light oil system, the tested heavy oil shows considerably improved recovery and less asphaltene deposition during high-concentration CO2 flooding. Therefore, although CO2 miscibility can hardly be achieved in heavy oil reservoirs, CO2 is of great interest due to its high solubility in heavy oil and significant oil viscosity reduction.