Numerical analysis of CO2 fracturing in shale: Effects of bedding structure, fluid properties, stress ratio, and pressurization rate

CO2 fracturing shows promise in unconventional gas reservoirs. However, differences in fluid properties and fracture evolution between CO2 fracturing and traditional water fracturing remain inadequately studied. This paper established a fluid–solid–damage coupling model that accounts for variations in compressibility and viscosity during water and CO2 fracturing. The differences in damage and flow properties were studied between water and CO2 fracturing under the same conditions. Furthermore, the effects of stress ratios and pressurization rates on damage and flow properties were systematically investigated for different bedding structures during CO2 fracturing. The results indicated that permeability, pore pressure, and viscosity increase significantly with damage accumulation but decrease along the fracture propagation direction, while the compressibility shows the opposite trend. The breakdown pressure for water fracturing is higher than that for CO2 fracturing by 19.2%, 10.9%, and 19% in non-bedding shale, parallel bedding shale, and orthogonal bedded shale, respectively. Comparisons of fracture network and cumulative failure number indicate that CO2 can be used to replace water as an effective fracturing fluid. During CO2 fracturing, the parallel bedding shale exhibits the lowest damage initiation pressure and breakdown pressure. Additionally, the fracturing failure number was the highest when the stress ratio was 0.5 for parallel bedding shale and 1 for orthogonal bedding shale. Under the stress ratio of 0.5, the damage initiation pressure and breakdown pressure are the lowest in both cases. Furthermore, an increase in the pressurization rate leads to a higher fracture-tip pressure, which reduces the fracture complexity and the time required for fracturing.