--> Feasibility Study of CO<sub>2</sub> Enhanced Shale Gas Recovery

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Feasibility Study of CO2 Enhanced Shale Gas Recovery

Abstract

Shale has very low permeability and porosity, however it stores significant amount of natural gas is in the state of absorbed gas within the organic matter. Part of the absorbed gas will desorb when pressure decreases, which is the major mechanism for shale gas primary production. The primary recovery of shale gas is very low due to its affinity to organic matter, and this recovery factor is also hard to improve by traditional enhanced gas recovery (EGR) methods owing to the low permeability and state of residual gas. A potential feasible EGR method for shale gas is by using CO2, and there are several reasons for this: CO2 has low viscosity which makes it easy to inject into formation; the affinity of shale to CO2 is much greater than methane, substantial absorbed natural gas can be freed from organic matter and then be produced; Injected CO2 will be trapped in shale permanently which can help to reduce greenhouse gas in atmosphere. Techniques including CO2 flooding and CO2 ‘huff-n-puff’ as shale gas EGR methods have been studied, however contradictory conclusions have been made on the feasibility. In this study, several major shale gas plays including Marcellus shale, Barnett shale and Montney shale are modeled for CO2 EGR. An equation of state based compositional reservoir simulator is used to simulate the multistage fractured well primary production, CO2 flooding and CO2 huff-n-puff. Sensitivity analysis is conducted on influencing factors such as formation thickness, total organic content (TOC), permeability, gas saturation, stimulated reservoir volume and soaking time. Based on this investigation, a criteria for the feasible CO2 application to enhance shale gas recovery is brought up.