2D and 3D Diffusive Mass Transfer in Nanoporous Shale Samples using X-Ray CT and Compared with NMR Results.

Characterization of rock samples is relevant to hydrocarbon production, geothermal energy, hydrogen storage, waste storage, and carbon sequestration. Shale systems, however, are more complex and are characterized by very small pore sizes, porosities, and permeabilities. In nm-sized pores characteristic of impermeable shale matrix, the continuum approximation progressively breaks down. Therefore, fluid transport in shale exhibits different transport mechanisms depending on the Knudsen number (ratio of mean free path to pore diameter) and the pore pressure. As pore size get smaller, fluid transport is dominated by diffusion. Diffusion models (similar to Ficks First Law) have been developed to express flow rate in different regimes and are based on diffusion coefficients. Last year, we used Ficks 1D model to evaluate the diffusion behavior. Now, this project aims to evaluate the diffusion coefficient in 2D and 3D in systems with major heterogeneities and anisotropic behavior. The rock samples are unfractured Wolfcamp shale cores (2.5 cm diameter by 6 cm long). X-ray Computed Tomography (CT) is used to quantify in situ porosity distribution and fluid flow. The mineralogy composition is obtained using Quantitative X-Ray Diffraction (QXRD). Rock density is also presented using Mercury Injection Capillary Pressure (MICP). Liquid-liquid diffusion coefficients are measured using X-ray CT imaging of the progress of mass transfer and compared with Nuclear Magnetic Resonance (NMR) results. The saturation fluid was n-decane and the tracer was 1-iododecane. The experiments were conducted at room temperature. The samples utilized have average porosities around 10%. Grain densities are between 2.61 to 2.64 g/mL for the evaluated samples. The liquid-liquid diffusion results with both techniques are on the same order of magnitude 10-10 m2/s. The authors did not observed reversibility during the diffusion experiments.