A new methodology to assess the maximum CO2 geosequestration capacity of shale reservoirs with SRV based on wellbore pressure

Abstract

Shale reservoirs are promising geological sites for CO2 storage due to their high total organic content (TOC) and the large-scale hydraulic fracturing operations. In order to critically evaluate a potential storage reservoir, fast, robust tools are needed to assess the CO2 storage capacity. Based on our previous work, an efficient method based on semi-analytical solution for calculating the maximum CO2 storage capacity in shale formations is derived, based on the injection wellbore pressure. The new methodology fully reflects the flow, diffusion, and adsorption processes of CO2 in shales. It also simulates natural fractures, hydraulic fractures, and the stimulated reservoir volume (SRV). The semi-analytical solution utilizing a Laplace transform and Stehfest numerical inversion is developed to evaluate the wellbore pressure and storage capacity in shale formations, which is verified using numerical simulations. A case study of the derived method on the Bakken Shale shows that the CO2 storage capacity is strongly controlled by the CO2 injection rate, adsorption index, and storage ratio. It is also found that the effective diffusion coefficient and mobility ratio affect the CO2 storage capacity during different periods of the CO2 storage process.