Numerical Simulation and Modeling on CO2 Sequestration Coupled with Enhanced Gas Recovery in Shale Gas Reservoirs

• Published in: Geofluids 2021-08, Vol.2021, p.1-15
• Main Authors: Zhan, Jie, Niu, Zhihao, Li, Mengmeng, Zhang, Ying, Ma, Xianlin, Fan, Chao, Wang, Ruifei
• Format: Article
• Language: English
• Subjects: Adsorption; Carbon dioxide; Carbon dioxide fixation; Carbon sequestration; Climate change; Demand; Energy demand; Energy transfer; Energy utilization; Engineering; Feasibility studies; Flow velocity; Gas flow; Gas recovery; Gas transport; Global warming; Greenhouse effect; Greenhouse gases; Hydraulic fracturing; Hydraulics; Injection; Injection wells; Mathematical models; Methane; Numerical models; Numerical simulations; Permeability; Porous media; Recovery; Reservoir performance; Reservoirs; Sedimentary rocks; Sensitivity analysis; Shale; Shale gas; Shales; Simulation; Simulators
• ISSN: 1468-8115; 1468-8123
• DOI: 10.1155/2021/9975296

CO2 geological sequestration in shale is a promising method to mitigate global warming caused by greenhouse gas emissions as well as to enhance the gas recovery to some degree, which effectively addresses the problems related to energy demand and climate change. With the data from the New Albany Shale in the Illinois Basin in the United States, the CMG-GEM simulator is applied to establish a numerical model to evaluate the feasibility of CO2 sequestration in shale gas reservoirs with potential enhanced gas recovery (EGR). To represent the matrix, natural fractures, and hydraulic fractures in shale gas reservoirs, a multicontinua porous medium model will be developed. Darcy’s and Forchheimer’s models and desorption-adsorption models with a mixing rule will be incorporated into the multicontinua numerical model to depict the three-stage flow mechanism, including convective gas flow mainly in fractures, dispersive gas transport in macropores, and CH4-CO2 competitive sorption phenomenon in micropores. With the established shale reservoir model, different CO2 injection schemes (continuous injection vs. pulse injection) for CO2 sequestration in shale gas reservoirs are investigated. Meanwhile, a sensitivity analysis of the reservoir permeability between the hydraulic fractures of production and injection wells is conducted to quantify its influence on reservoir performance. The permeability multipliers are 10, 100, and 1,000 for the sensitivity study. The results indicate that CO2 can be effectively sequestered in shale reservoirs. But the EGR of both injection schemes does not perform well as expected. In the field application, it is necessary to take the efficiency of supplemental energy utilization, the CO2 sequestration ratio, and the effect of injected CO2 on the purity of produced methane into consideration to design an optimal execution plan. The case with a permeability multiplier of 1,000 meets the demand for both CO2 sequestration and EGR, which indicates that a moderate secondary stimulation zone needs to be formed between the primary hydraulic fractures of injection and production wells to facilitate the efficient energy transfer between interwell as well as to prevent CO2 from channeling. To meet the demand for CO2 sequestration in shale gas reservoirs with EGR, advanced and effective fracking is essential.