No abstract

This study provides the engineering science underpinnings for improved characterization and quantification of the interplay of gases with kerogen and minerals in shale. Natural nanoporous media such as shale (i.e., mudstone) often present with low permeability and dual porosity, making them difficult to characterize given the complex structural and chemical features across multiple scales. These structures give nanoporous solids a large surface area for gas to sorb. In oil and gas applications, full understanding of these media and their sorption characteristics are critical for evaluating gas reserves, flow, and storage for enhanced recovery and CO2 sequestration potential. Other applications include CO2 capture from industrial plants, hydrogen storage on sorbent surfaces, and heterogeneous catalysis in ammonia synthesis. Therefore, high-resolution experimental procedures are demanded to better understand the gas–solid behavior. In this study, CT imaging was applied on the sub-millimeter scale to shale samples (Eagle Ford and Wolfcamp) to improve quantitative agreement between CT-derived and pulse decay (mass balance) derived results. Improved CT imaging formulations are presented that better match mass balance results, highlighting the significance of gas sorption in complex nanoporous media. The proposed CT routine implemented on the Eagle Ford sample demonstrated a 17% error reduction (22% to 5%) when compared to the conventional CT procedure. These observations are consistent in the Wolfcamp sample, emphasizing the reliability of this technique for broader implementation of digital adsorption studies in nanoporous geomaterials.

No abstract

In this work, we lay the experimental groundwork for measuring CO2 storage, and other industry-relevant gases, in shale on a core scale. This works emphasizes the role of adsorption on gas storage using two core samples (one Eagle Ford and one Wolfcamp). Mass balance and Computed Tomography (CT) methods are used independently to co-validate our results. The validation process allows for confidence in the accuracy of the CT visualizations. In addition, the CT method significantly reduces the characterization time needed for measuring gas storage before running any further investigations related to gas flow and recovery. The pulse-decay technique is initially used to quantify apparent porosity, permeability, and adsorption for He, N2, Kr, CH4, and CO2 at room temperature (and 42 °C in some cases) up to 800 psia pore pressure. In the case of Kr, Eagle Ford core (EF1) is imaged at the end of each pressure pulse step to compare CT-derived to pulse decay derived results. At 650 psia, CO2 and Kr storativity (SCF of gas per ton of rock) in sample EF1 have roughly 4.5× and 2× the storativity of He, respectively. Absolute adsorption of CO2 (181 SCF/Ton) is significantly greater than N2 (5 SCF/Ton) and Kr (45 SCF/Ton) at 650 psia pore pressure. Furthermore, our proposed CT approach yields a good match to the mass balance characterization results for Kr as opposed to the conventional CT formulation. Permeability results show negative correlation between adsorption affinity of gas and sample liquid-like permeability. In the case of Kr and N2 measurements on sample EF1, the greater compressibility of Kr is overcome by its larger adsorption affinity resulting in a greater than N2 permeability at lower pore pressures but lower permeability at higher pore pressures. The Wolfcamp sample (WC2) captures a potentially irreversible effect of CO2 on permeability attributed to either permanent matrix swelling or matrix softening. This study bridges both CT and mass balance derived results to ensure accurate visualization of the physics during characterization. Both methods show a better displacement of in-situ Kr (proxy for CH4) with CO2 as compared to N2 injection. CT visualizations of both gas displacement experiments show two relatively permeable flow pathways emerge during early times.