CO2-Driven Enhanced Gas Recovery and Storage in Depleted Shale Reservoir- A Numerical Simulation Study

Increased emissions of carbon dioxide (CO₂), especially from the combustion of fossil fuels, are being linked to global climate change and are of considerable concern. These concerns are driving initiatives to develop carbon management technologies. At present, several geological CO₂ sequestration technologies , such as CO₂ injection into saline aquifer, CO₂-EOR, CO₂-ECBM, and so forth, have been studied to minimize the CO₂ release into the atmosphere, and these projects have been operating all over the world.

One option for storage and enhanced gas recovery may be organic-rich shales, which CO₂ is preferentially adsorbed and displacing methane. The continuing development of the Marcellus Shale has the potential to and positively impact the future of CCS in the Appalachian Basin. Therefore, there is a great need for performing comprehensive simulation studies to better understand CO₂ injection process in shale gas reservoir.

This paper presents a comprehensive analysis of technical aspects of CO₂-Enhanced Gas Recovery and storage in depleted shale gas reservoir using numerical simulation. The first step in the process of modeling and simulation of CO₂ injection is to evaluate a range of injection scenarios and then, based on results of that modeling effort; propose an appropriate set of injection cases. The most appropriate injection scenarios attempt to maximize methane production while delaying CO₂ breakthrough time (BT) and maximizing the amount of CO₂ that is stored.

With this strategy in mind, it is impractical to inject CO₂ into all the laterals in a pad which are hydraulically fractured. Instead, the appropriate set of injector-producer laterals must be selected with the aim of enhancing methane production from the offset well(s). This is due to the fact that communication between hydraulic fractures in the so-called SRV regions contributes to early breakthrough.

Different CO₂ injection scenarios using the existing wells and based on different well pattern (injector and producer spacing), different reservoir characteristics and different operational constraint based on the history matched numerical reservoir simulation model are defined and the best practices to enhance methane recovery and to minimize CO₂ production while maximizing the amount of stored CO₂ in shale formation is proposed.