Open Access

ARTICLE

Numerical Investigation of Carbon Capture, Utilization, and Storage–Enhanced Gas Recovery

Nan Qin¹, Shaofeng Ning^2,*, Zihan Zhao^1,2, Yu Luo¹, Bo Chen¹, Xiaoxu Liu¹, Yongming He²

1 Petro China Southwest Oil and Gas Field Exploration and Development Research Institute, Chengdu, 610041, China
2 College of Energy, Chengdu University of Technology, Chengdu, 610059, China

* Corresponding Author: Shaofeng Ning. Email:

(This article belongs to the Special Issue: Multiphase Fluid Flow Behaviors in Oil, Gas, Water, and Solid Systems during CCUS Processes in Hydrocarbon Reservoirs)

Fluid Dynamics & Materials Processing 2025, 21(12), 2997-3009. https://doi.org/10.32604/fdmp.2025.074456

Received 11 October 2025; Accepted 16 December 2025; Issue published 31 December 2025

Abstract

Balancing CO₂ emission reduction with enhanced gas recovery in carbonate reservoirs remains a key challenge in subsurface energy engineering. This study focuses on the Maokou Formation gas reservoir in the Wolonghe Gas Field, Sichuan Basin, and employs a mechanistic model integrated with numerical simulations that couple CO₂–water–rock geochemical interactions to systematically explore the principal engineering and chemical factors governing Carbon Capture, Utilization, and Storage–Enhanced Gas Recovery (CCUS–EGR). The analysis reveals that both the injection–production ratio and gas injection rate exhibit optimal ranges. Maximum gas output under single-parameter variation occurs at an injection–production ratio of 0.7 and an injection rate of 130,000 m³/d, while coordinated optimization of both parameters is essential to achieve the highest production enhancement. Excessively high injection–production ratios, however, may induce gas channeling and reduce the ultimate recovery factor. Chemical composition of the injected gas also strongly influences recovery. In the heterogeneous carbonate reservoir considered, a CO₂–N₂ mixed gas mitigates gravity segregation due to its lower density, expanding sweep efficiency and improving overall gas recovery compared to pure CO₂ injection. CO₂–water–rock reactions further modify reservoir properties. Near the injection well, acidic dissolution enhances porosity, whereas near the production well, a dynamic interplay of ion migration, pressure–temperature variations, and secondary mineral precipitation produces complex porosity evolution. Initial precipitation reduces porosity, while subsequent acidic dissolution partially restores it, creating a heterogeneous and time-dependent porosity profile.

---

Keywords

---