Evaluation of Gas Flooding Effect in Mahu Tight Sandstone Reservoir
Authors: Zhao Z. W. , Zhang S. C. , Zou Y. S. , Zhang X. H. , Zhu D. Y. , Liu S. K. , Yang P. , Liu L. 
Published: August 2024

The pore structure of low-permeability tight gravel reservoirs in Mahu is complex, with low permeability and high clay content. This results in rising injection pressures during water flooding, severe under-injection in water wells, and challenges in maintaining reservoir pressure, thereby affecting reservoir development effectiveness. Gas has relatively strong permeability in tight reservoirs, exhibits good injectability, and can avoid various sensitivity issues caused by water injection. Therefore, gas injection development shows potential applications in low-permeability tight gravel reservoirs. This study primarily employs physical simulation to evaluate the oil displacement effects of CO2 and hydrocarbon gases in low-permeability tight gravel reservoirs. CO2 and hydrocarbon gases have good solubility in crude oil. Initially, using a PVT apparatus, this study investigates the variation of crude oil properties after dissolving different amounts of CO2 or hydrocarbon gases. By controlling the injection of hydrocarbon gases or CO2 to around 15%, significant improvements in crude oil properties and economic benefits can be achieved. Results from laboratory experiments on long cores of low-permeability tight gravel reservoirs indicate that at 36 MPa, the efficiency of hydrocarbon gas miscible flooding is 63.86%, while at 19 MPa, the efficiency of CO2 miscible flooding is 60.55%. Hydrocarbon gas miscible flooding shows slightly higher efficiency, while CO2 miscible flooding operates at lower pressures, demonstrating better adaptability in reservoirs with lower pressures. These findings provide valuable guidance for gas injection development in tight sandstone gravel reservoirs.

1. INTRODUCTION

Located in the northwestern part of the central depression of the Junggar Basin, the Mahu Depression is currently the largest gravel oil field in the world, harboring immense development potential. Among these, the reservoir of the Baikouquan Formation in the Mahu 18 Well Block is the primary target for unconventional tight oil development, which has become a focal point for production enhancement and stabilization in recent years (Abulimiti et al., 2015; Rui et al., 2016; Tao et al., 2019; Wenlong et al., 2023; Wu et al., 2020; Yong et al., 2019; Yu, Wang, & Wang et al., 2022). Unlike conventional sandstone reservoirs, the tight gravel reservoirs in Mahu exhibit complex pore structures and high heterogeneity, leading to unique flow behavior and increased development challenges. The presence of high clay mineral content (exceeding 16%, even surpassing 30%), primarily consisting of water-sensitive montmorillonite and illite interlayers, exacerbates the reservoir's water sensitivity during development (Jia et al., 2017; Lu et al., 2019; Xi et al., 2021; Yu, Wang, & Fan et al., 2022; Yu, Wang, & Jiang et al., 2022; Yu et al., 2023). These characteristics result in a continuous decline in well productivity, prominent issues of water channeling, and difficulties in maintaining reservoir pressure, consequently reducing development efficiency, with monthly production decline rates reaching 40%-60%. To address the challenges posed by the complex pore structure and strong water sensitivity, and to improve the development effectiveness of the tight gravel reservoirs in Mahu, this study employs gas injection techniques (CO2, hydrocarbon gases) to assess displacement effects, thereby providing theoretical insights for the efficient exploitation of tight gravel formations.