Abstract: Tight conglomerate reservoirs are featured with extremely low permeability, strong heterogeneity and poor water injectivity. CO2 huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs, owing to its advantages in reducing oil viscosity, improving mobility ratio, quickly replenishing formation pressure, and potentially achieving a miscible state. However, reliable in-house laboratory evaluation of CO2 huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure. In this study, we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO2 injection in a tight conglomerate reservoir. The impacts of depletion degree, pore volume injection of CO2 and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure. Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency (first increased and then decreased) with increased CO2 injection volume and soaking time. The lower oil recoveries under excess CO2 injection and soaking time were attributed to limited CO2 dissolution and asphaltene precipitation. This work guides secure and reliable laboratory design of CO2 huff-n-puff in tight reservoirs with high formation pressure.