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The design of oil recovery processes by gas injection or vapor solvent relies on knowledge of diffusion coefficients to enable meaningful production predictions. However, lab measurements of diffusion coefficients are often performed on bulk fluids, without accountability for the hindrance caused by the pore network structure and tortuosity of porous media. As such, our ability to predict effective diffusion coefficients in porous rocks is inadequate and, additional laboratory work is needed to investigate the impact of the medium itself on transport by diffusion. In addition, experimental data on multi-phase diffusion coefficients are particularly scarce for tight rocks. This study therefore proposes an experimental methodology, based on a pressure-decay technique, to measure diffusion of injected gas in oil saturated porous rocks. A diffusion experiment of gas into bulk oil (without porous medium) provides an upper limit estimation of this gas-liquid diffusion coefficient. Diffusion experiments using limestone and Bakken shale provide insight into different degrees of restriction in high permeability versus low permeability media. Two analytical models and one numerical model were implemented and compared to determine the diffusion coefficients from the time-dependent experimental pressure-decay data. These diffusion coefficients were found in agreement with literature on corresponding data, demonstrating the validity of the modeling approaches used. Results indicate considerable hindrance to diffusion in porous media relative to bulk oil and relates to the tortuosity and constrictivity of the rock matrix. The diffusion coefficient of methane in bulk oil is 3.8 × 10−9 m2/s. In our limestone sample, this diffusion coefficient drops by one order of magnitude, ranging between 1.5 to 6.5 × 10−10 m2/s and, it drops by another order of magnitude in the Bakken shale sample to 2.0 × 10−11 m2/s.

The efficiency of miscible gas flooding relies on the mass transfer rate of species from one phase to another. Determining the diffusion coefficient of a gas-oil system is a critical factor to characterize this transfer phenomenon between gas and oil. Many gas-oil systems are being investigated to measure the diffusion coefficients, losing sight of the hindrance effect under reservoir conditions due to the pore network structure of porous media. Therefore, effective diffusion coefficients in porous media, which have more practical guiding significance, need further investigation. In this study, an experimental methodology based on the pressure-decay technique is proposed for capturing the gas-oil diffusion signals in porous rocks. A numerical model developed by our research group is implemented for estimating all diffusion parameters under different conditions. Results demonstrate the feasibility of this numerical simulation model. Experimental work and numerical simulation were performed on three different scenarios: gas-liquid diffusion in bulk Bakken oil, oil-saturated limestone and Bakken shale samples. The results present quantitative insight into the sensitivity of the diffusion coefficients to the degree of porous media restriction. Moreover, effective diffusion coefficients respond to pore network tortuosity, where more tortuous pore networks provide stronger hindrance effect on the molecular diffusion process. According to the results, this study can provide a technical support for correlating the effective diffusion coefficient to the relevant properties of rocks, which is helpful for establishing more accurate simulation models when the effective diffusion coefficients are missing.

Shale gas reservoir has become a crucial resource for the past decade to sustain growing energy needs while reducing the carbon intensity of energy systems relative to other fossil fuels. However, these reservoirs are geologically complex in their chemical composition and dominance of nano-scale pores, resulting in limited predictability of their effective storage capacity. To predict gas storage and estimate volumetric gas-in-place, in-situ gas properties need to be defined. However, only a few direct experimental measurements on in-situ gas properties are available in the literature, and the interactions between gas and the surrounding surface area of the medium remain poorly understood. In this study, gas invasion experiments were conducted in conjunction with 3D X-ray micro-CT imaging on three different shales, i.e., Bakken, Haynesville and Marcellus. Results show evidence of increased storage capacity in all cases, with different degrees of gas densification across the three shale specimens. The average of measured in-situ xenon density within the Bakken, Haynesville and Marcellus shale samples were found to be 171.53 kg/m3, 326.05 kg/m3 and 947 kg/m3, respectively. These measured densities are higher than their corresponding theoretical free gas density, though lower than the xenon density at boiling point, indicating that current practices of estimating adsorbed gas and gas in place, using boiling point liquid density, may be overestimated. The xenon densification factor in the Marcellus sample was found to be 7.4, indicating the most significant degree of localized densification. This densification factor drops to 2.6, and to 1.4, in the Haynesville and the Bakken sample, respectively. Characterization of shale composition and pore structure are presented, in order to assess the shale properties controlling in-situ gas density and storage capacity. Results indicate that the observed degree of gas densification in shales can be attributed to surface area and pore size. The findings in this work provide valuable reference for simulation to much more accurately predict gas storage in shales. More importantly, the contribution of this work lay a foundation to evaluate excess storage capacity of various gases in ranging tight formations.