Traditional core flooding experiments can only be used post breakthrough while what happens in the core prior to this time is vital to understand multiphase flow phenomenon for more successful EOR operations. We can overcome this obstacle through a visualized fluid displacement scheme. This can ultimately provide us with a reliable relative permeability curve that can lead to a more accurate reservoir simulation outcome in the field scale. In this study, NMR imaging is employed in a water flood experiment in conjunction with two separate numerical two-phase flow simulation methods (FDM and FEM), to reproduce experimental data. Using the Brooks-Corey equation, random pore size distribution indices (λ) are selected to generate relative permeability curves. Moreover, simulations are performed with FDM, and oil displacement efficiency, saturation maps, and saturation profiles are generated and compared to the experimental results. Next, FEM was employed in COMSOL for further validation and FDM results were found in agreement with the experiments. This way, an appropriate relative permeability curve was generated and assigned to the sample. Results suggest that λ of 0.2 generated the best numerical results with an MSE value of 0.009 in oil displacement efficiency curves, comparable to the experiments. Collectively, integration of imaging techniques with routine experimental fluid displacement procedures presented a detailed insight into complicated nature of multiphase flow phenomena in geomaterials.

The Devonian Antrim Shale is an unconventional biogenic gas accumulation with a technical recoverable resource of 19.9 Tcf. However, major knowledge gaps remain regarding understanding of the source rock potential, organic facies assemblages and paleo-depositional conditions of the Antrim Shale members. This work utilized Rock-Eval pyrolysis, reflected light microscopy and solid bitumen reflectance to characterize the source rock quality, organo-facies assemblages, and thermal maturity of the various Antrim Shale members at three different localities in the Michigan Basin. Results showed that the Lachine and Norwood members are richer in organic matter (up to 24 wt%) than the Upper and Paxton members (<8 wt%). Organic matter is mainly dominated by marine Type II kerogen in the black shales of the Lachine and Norwood members, and by Type II and Type II/III in the Paxton Member. Telalginite, which is represented mainly by Tasmanites and Leiosphaeridia cysts, is the dominant organic matter in the black shale members where they account for about two-thirds of the organic matter composition. Solid bitumen, which accounts for less than one-third of the organic matter composition, is second after alginite. Both alginite and solid bitumen populations decline in abundance progressively in the Upper and Paxton members at the expense of inertinite and vitrinite. The dominant organofacies groups in the studied Antrim Shale members can be assigned to the BP type B and type D/E. Organic matter maturity determined from Rock-Eval Tmax and bitumen reflectance varies from immature to marginally mature across the Michigan Basin. The results confirmed that sediment burial depth and lateral position in the basin controlled organic facies assemblages within the Antrim Shale members.

Characterizing the kerogen-hosted pore structures is essential to understand the adsorption, transport and storage potential in organic-rich shale reservoirs. In this paper, we first separated the organic matter (kerogen) from the mineral matrix in four different shale samples of the Bakken Formation with different thermal maturities and then analyzed their chemical compositions using the wide-angle X-ray scattering (WAXS) method. Next, we acquired small-angle X-ray scattering (SAXS) to characterize the structure of the organic matter and see how these two will relate. The WAXS results showed that the isolated kerogens have high purity (free of inorganic minerals) and retain different chemical compositions. Moreover, SAXS analysis revealed that the isolated kerogens have similar radius of gyration (Rg) which is around 90 Å and the molecules are in the compact mode. Based on the pore size distribution analysis from the SAXS data, two main peaks were found in all of these four samples with one peak less than 40 Å and the other one larger than 1000 Å. Also, the TEM images revealed that Sample 1 is abundant in pores with sizes around 20 nm while Sample 2 does not have pores of that size, which agrees with the results from the pore size distribution that was obtained from the SAXS method. Ultimately, this study exhibits how different analytical instruments can provide us with useful information from complex structures of geomaterials. For all the samples, two main peaks can be found with one peak less than 40 Å and the other one larger than 1000 Å。