Open Access

ARTICLE

CO₂ Injection to Mitigate Reservoir Damage in Edge/Bottom-Water Condensate Gas Reservoirs

Wen Wang^1,*, Yulong Zhao¹, Bo Li², Bowen Guan¹, Haoran Sun^1,3, Tao Zhang¹

1 State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, 610500, China
2 PetroChina Xinjiang Oilfield Company, Karamay, 834000, China
3 PetroChina Jidong Oilfield Company, Tangshan, 063299, China

* Corresponding Author: Wen Wang. Email:

(This article belongs to the Special Issue: Fluid and Thermal Dynamics in the Development of Unconventional Resources III)

Fluid Dynamics & Materials Processing 2025, 21(9), 2331-2357. https://doi.org/10.32604/fdmp.2025.068990

Received 11 June 2025; Accepted 11 September 2025; Issue published 30 September 2025

Abstract

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. CO₂ injection offers a promising solution by alleviating condensate blockage, suppressing water influx, and simultaneously enabling geological CO₂ storage. Accordingly, research on optimizing CO₂ 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^TM and WinProp^TM. 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 CO₂ 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 CO₂ at a rate of 5 × 10⁴ m³/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%.

---

Keywords

---