CO₂ flooding in low-permeability and tight oil reservoirs is frequently compromised by severe gas channeling, which significantly reduces oil recovery and sweep efficiency. While foam flooding can effectively mitigate CO₂ channeling by trapping CO₂ within lamellae, its stability deteriorates under harsh high-temperature, high-salinity reservoir conditions, compromising its effectiveness. Furthermore, foam flow in porous media involves constant foam generation, collapse and propagation, making its flow behaviors difficult to predict. To address these challenges, a new foaming agent with satisfactory regenerative capability is developed to maintain gas mobility control under harsh reservoir conditions. The multiphase flow behaviors during CO₂ foam flooding are predicted using pore network modeling to obtain the corresponding relative permeability curves, which are further incorporated into a reservoir simulator to evaluate field-scale foam flooding performances, as well as optimize injection strategies. This multi-scale modeling approach establishes a quantitative link between pore-scale foam behaviors and field-scale oil recovery performances, offering new insights into carbon capture and utilization with enhanced oil recovery in low-permeability and tight reservoirs.