Evaluation of CO2 injection into shale gas reservoirs considering dispersed distribution of kerogen

Injection of CO2 into shale gas reservoir has gained great interest due to its potential for both enhanced gas recovery and permanent CO2 sequestration. It is revealed that the heterogeneous shale rock is comprised of organic matter (kerogen) and inorganic matter (including clay, quartz, pyrite etc.) and kerogen is a dispersed phase. The distinct physio-chemical properties between organic and inorganic matter that reflect in the matrix permeability, pore size, wettability and gas occurring status, lead to different gas transport and flow performance in porous media. However, most previous studies built up the simulation models by using one continuum in shale matrix without distinguishing organic and inorganic matter, which may lead to inaccurate evaluation of CO2 injection performance. In this work, the shale matrix is subdivided into organic matrix and inorganic matrix with their unique characteristics. The organic matrix is dispersed and embedded in the inorganic matrix. The inorganic matrix is directly connected to the hydraulic/natural fractures that created explicitly by embedded discrete fracture model. Both huff-n-puff and gas flooding schemes in shale gas reservoir are examined. The simulation results indicate that the CO2 storage capacity of shale reservoir is significantly reduced if dispersed distribution of kerogen is considered. Most of injected CO2 enters inorganic pores while limited amount of CO2 can contact the kerogen due to the low flow conductivity between organic and inorganic matrix. The CO2 in inorganic pores will be quickly reproduced without replacing adsorbed methane in kerogen. Sensitivity tests show that total organic carbon and injection rate have trivial effects on the efficiency of CO2 injection while gas diffusion is a key factor for evaluation.