Investigations of CO2 storage capacity and flow behavior in shale formation

CO2 storage, CO2 stimulation, CO2-enhanced oil recovery (EOR), and CO2-enhanced gas recovery (EGR) in shale reservoirs have recently attracted attention. Thorough investigations mimicking high pressure and high-temperature subsurface conditions are necessary to understand the interaction between CO2 and organic-rich shales, advance the fundamental understating of flow mechanisms in unconventional reservoirs, and successfully implement a field project. Most of the previous work focused on one aspect of adsorption, flow behavior, and reservoir numerical simulation. We suggest that a single approach investigation may lead to incomplete conclusions of CO2 injection in shales. This work comprehensively evaluates CO2 storage potential and injectivity in the Bakken Formation through various approaches. Samples are tested from the Lower Bakken Shale (LBS), the Middle Bakken (MB), and the Upper Bakken Shale (UBS). In terms of absolute and Gibbs/excess, adsorption isotherms of these two types are both measured, and the adsorbate density is estimated. We differentiate two adsorption isotherms and emphasize the correct use of the isotherm in the current commercial reservoir simulator, which is relatively obscure in the existing literature body. Nuclear magnetic resonance (NMR) confirms a portion of bitumen/absorption mobilization because of CO2 exposure. In the compositional simulations of CO2 injection in shales, several novel conclusions are obtained regarding analyzing main control factors; the most important one is that adsorption outweighs molecular diffusion in determining CO2 injection rate.

Automated summary

Research indicates that comprehensive evaluation of CO2 storage potential and injectivity in the Bakken Formation through various methods is essential. Adsorption is a key factor determining CO2 injection rate, outweighing molecular diffusion.