Determination of inorganic and organic permeabilities of shale

Shale oil resources have become important energy supplies worldwide, but their storage features and flow mechanisms remain unclear. It is now well-accepted that shale formations are complex systems with both inorganic and organic contents. This study aims to characterize the permeabilities for inorganic and organic pore systems separately in shale samples using an innovative modeling approach validated with experimental data. Oil and water vacuum–imbibition tests were first conducted along with helium porosity measurements for four shale rock samples. A mathematical model considering imbibition and diffusion was then proposed and used to match the lab-measured oil and water imbibition curves. The critical parameters for these shale samples, including inorganic/organic porosities, fluid saturations, and permeabilities were successfully determined using this approach. Among all the samples in the study, the results showed that 33.93 to 40.54% of total oil in place was stored inside kerogen as either the free oil within the organic pores or the dissolved oil. Moreover, the flow of this part of the oil was controlled by the organic permeability as well as by the diffusion coefficient, which was different than the flow character of oil in the inorganic pore system. The organic permeabilities of the samples used in this study were between 2.24 × 10−6 and 1.59 × 10−5 md, which were 243 to 2741 times less than each sample's corresponding inorganic permeability. The sensitivity analysis indicated that organic permeability significantly affected the oil imbibition rate. The proposed methodology should be adopted in future reservoir characterizations, and the determined permeabilities for both inorganic and organic pore material should accordingly be considered in future reservoir simulations in order to accurately describe fluid flow in shale reservoirs.