Feasibility study of CO2 injection at the top of tight conglomerate reservoir in Mahu Sag, Junggar Basin, China

Introduction The 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. Methods Long-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. Results Top 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. Discussion This work demonstrates that leveraging CO₂ miscibility to stabilize displacement fronts provides an effective strategy for tight reservoir development, particularly in dipping formations.