IntroductionThe Mahu Sag tight conglomerate reservoirs in the Junggar Basin exhibit rapid pressure depletion and severe degassing in horizontal wells due to low reservoir-saturation pressure differences (<5 MPa), resulting in poor recovery efficiency under primary depletion. This study investigates the feasibility of early-stage CO₂ injection at the reservoir top to enhance oil recovery through gravity-assisted displacement.MethodsLong-core gravity drainage experiments and numerical simulations were conducted to evaluate the effects of formation dip angle (0°∼90°) and permeability (0.85∼1.7 mD) on displacement efficiency. Comparative analyses of CO₂, N₂, and hydrocarbon gas performance were performed.ResultsTop CO₂ injection significantly improves recovery when the formation dip exceeds 10° and permeability is >0.85 mD. CO₂ exhibits superior pressure maintenance and forms a stable near-miscible oil-gas interface, delaying gas breakthrough (13.5 years for CO₂ vs. 6.5 years for N₂) and achieving 38.7% recovery in the gas chamber – double that of other gases. The small phase contrast between CO₂ and crude oil enables uniform vertical advancement, mitigating gas channeling risks. Furthermore, a hybrid well pattern (vertical injectors + horizontal producers) optimizes sweep efficiency, with vertical wells enhancing multilayer coverage and stability.DiscussionThis work demonstrates that leveraging CO₂ miscibility to stabilize displacement fronts provides an effective strategy for tight reservoir development, particularly in dipping formations.