TY  - EJOU
AU  - Wang, Wen 
AU  - Zhao, Yulong 
AU  - Li, Bo 
AU  - Guan, Bowen 
AU  - Sun, Haoran 
AU  - Zhang, Tao 

TI  - CO<sub>2</sub> Injection to Mitigate Reservoir Damage in Edge/Bottom-Water Condensate Gas Reservoirs
T2  - Fluid Dynamics \& Materials Processing

PY  - 2025
VL  - 21
IS  - 9
SN  - 1555-2578

AB  - Condensate gas reservoirs have attracted increasing attention in recent years due to their significant development potential and dual value from both natural gas and condensate oil. However, their exploitation is often hindered by the dual challenges of retrograde condensation and water invasion, which can markedly reduce recovery factors. CO<sub>2</sub> injection offers a promising solution by alleviating condensate blockage, suppressing water influx, and simultaneously enabling geological CO<sub>2</sub> storage. Accordingly, research on optimizing CO<sub>2</sub> injection to mitigate formation damage is critical for the efficient development and management of edge- and bottom-water condensate gas reservoirs. In this study, a long-core displacement mechanism model was constructed using CMG-GEM<sup>TM</sup> and WinProp<sup>TM</sup>. The model simulates reservoir depletion from initial conditions (41.2 MPa, 102.5°C) to the current reservoir pressure (13.5 MPa), followed by gas injection. It was then upscaled to the edge- and bottom-water reservoir scale to capture complex fluid phase behavior, enabling a multi-factor coupled optimization of CO<sub>2</sub> injection strategies. Model reliability was verified through comparison with core experimental results. Subsequently, the effects of geological parameters (e.g., reservoir permeability and rhythmic heterogeneity) and engineering parameters (e.g., injection pressure and rate) on reservoir performance were systematically evaluated. The results indicate that appropriate target zone selection and optimization of injection pressure and rate—avoiding formation fracturing and preventing gas channeling—can substantially improve reservoir development outcomes. Applying this approach to the K Gas Reservoir, the optimal strategy involved injecting CO<sub>2</sub> at a rate of 5 × 10<sup>4</sup> m<sup>3</sup>/d, restoring pressure to 22.5 MPa in a composite rhythmic reservoir with an average permeability of 10 mD. This scheme increased the condensate oil recovery factor by 18.7 percentage points (from 43.9% to 60.9%) while reducing the water-cut rise rate by approximately 34%.
KW  - CCUS; condensate gas reservoir; retrograde condensation; water invasion; CO<sub>2</sub> injection; enhanced gas recovery (EGR)

DO  - 10.32604/fdmp.2025.068990