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

Wenya Zhai¹Chenguang Cui¹Xiuquan Hu¹Siyuan Li¹Yueli Feng¹Long Tan¹Jigang Zhang¹Ruihai Jiang²Fengqi Tan^2*

• ¹PetroChina Xinjiang Oilfield Company, Karamay, China
• ²University of Chinese Academy of Sciences, Beijing, Beijing, China

The Mahu Sag tight conglomerate reservoirs in the Junggar Basin, characterized by low reservoir-saturation pressure differences (<5 MPa), suffer from rapid pressure depletion and severe degassing in horizontal wells, leading to poor recovery efficiency under primary depletion. In this study, the feasibility of early-stage CO₂ injection at the top of reservoir to enhance oil recovery through gravity-assisted displacement was investigated. 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. The results demonstrate that top CO₂ injection significantly improves recovery when the formation dip exceeds 10° and permeability is >0.85 mD. Compared to N₂ and hydrocarbon gas, CO₂ exhibits superior pressure maintenance and forms a stable near-miscible oil-gas interface, significantly delaying gas breakthrough (13.5 years for CO₂ vs. 6.5 years for N₂) and achieving 38.7% recovery in the gas chamber, doubling 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 and horizontal producers) optimizes sweep efficiency, with vertical wells enhancing multilayer coverage and stability. This work provides a novel strategy for tight reservoir development by leveraging CO₂ miscibility to stabilize displacement fronts.