Residual oil effects on thermo-hydro-mechanical response and fracture reactivation during CO2 storage in depleted reservoirs

Low-temperature CO 2 injection into depleted oil reservoirs may reactivate natural fractures through thermo-hydro-mechanical (THM) coupling, yet most existing models neglect residual oil by simplifying the process as CO 2 –water two-phase flow. This study develops a coupled THM model incorporating oil–CO 2 –water three-phase flow, with the Stone I relative permeability model and the J-function used to describe phase mobility and capillary pressure. The model is compared with a conventional two-phase model to evaluate CO 2 migration, pressure and temperature evolution, stress changes, and fracture reactivation in depleted oil reservoirs. Results show that slip risk is spatially heterogeneous and concentrated near fracture tips, especially at the lower tip of fracture F1. Under baseline conditions of 2 kg/s injection rate, 273.15 K injection temperature, and 10 MPa initial pore pressure, F1 reaches the slip threshold after 7.33 years, corresponding to a stability-constrained cumulative injected CO 2 mass of 462.1 thousand tonnes. At 3.5 kg/s, the two-phase model predicts reactivation 0.77 years earlier than the three-phase model, with corresponding cumulative injected masses of 397.2 and 482.4 thousand tonnes, respectively, a difference of 21.4%. Increasing the injection temperature from 273.15 to 293.15 K raises the three-phase stability-constrained cumulative injected mass from 462.1 to 624.5 thousand tonnes by delaying fracture reactivation, while lower initial pore pressure provides a greater stability margin. These results demonstrate that residual oil should be considered in fracture-stability assessments for CO 2 storage in depleted oil reservoirs.