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Summary Four intact 2.54-cm-diameter cores from different shale plays (Barnett, Haynesville, Eagle Ford, and Permian Basin) were analyzed for their gas-storage capacity by use of a novel multiscale-imaging methodology spanning from centimeter to nanometer scale. Gas-storage (free and sorbed gas) capacity was investigated at the core scale with carbon dioxide (CO2) and krypton (Kr) by use of X-ray computed tomography (CT) with voxel dimensions of 190 × 190 × 1000 µm. Also, 2D tiled images were acquired with a scanning electron microscope (SEM) and stitched together to form 2.54-cm-diameter mosaics with a pixel resolution of 1.5 µm. Multiscale-image registration was then carried out to align the CT data with the SEM mosaics. Energy-dispersive spectroscopy (EDS) generated elemental spectra maps and subsequent component maps for regions with either substantial or minimal gas storage to assess the interplay of structural features (e.g., fractures) and matrix composition with respect to gas accessibility and storage. Registration of CT scans (vacuumed and gas-filled) as well as 190-µm-resolution CT-derived gas-storage maps with 1.5-µm-resolution SEM mosaics is straight forward for samples with dense features (such as calcite-filled fractures) that are resolvable by CT imaging. Alignment methods were developed for samples lacking these features, including registration marks by use of silver paint and intermediate-resolution microCT scans with cubic voxel dimensions of 27 µm. After alignment, the relationship of enhanced storage zones with open fractures and reduced storage regions with secondary mineralization (such as nodules) is apparent for the carbonaceous samples. For the clay-rich Barnett sample, fracture-filling calcite is associated with reduced storage similar to the other samples; however, secondary carbonate cementation within the clay matrix aligns with regions with substantial Kr- and CO2-gas storage. In contrast, clay-rich matrix regions lacking secondary carbonate cementation exhibit minimal gas-storage potential. Causes for this unexpected result include reduced gas accessibility and, possibly, low organic-matter content in the clay-rich matrix compared with secondary cemented matrix. These gas-sorption experiments prove the feasibility of dynamic core- to nanometer-scale CT/SEM/EDS image registration to improve sample characterization. To our knowledge, this is the first investigation of core-scale CO2-gas storage using multiscale imaging. CT and SEM image registration reveal spatial details regarding gas accessibility and storativity at the core scale. This work also supports the potential of carbon storage in shale formations and guides engineers toward optimal CO2-injection zones for enhanced gas recovery.

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Dynamic column breakthrough (DCB) measurements were carried out on idealized shale samples for the first time, based on a custom-designed system. To better understand the contribution of different shale minerals on flow and storativity, measurements were carried out on composition-controlled shales having known weight percentages of total organic carbon (TOC) and illite. CO 2 was assessed for its potential for sequestration, as well as its applicability as a fracturing fluid for enhanced gas recovery in shale formations. Experimental results reveal an increase in permeability and CO 2 adsorption with either increasing TOC or illite content. This is attributed to the complex porous structure of kerogen, as well as the interlayering characteristics of clay minerals, resulting in large surface area and pore volume ratios. Permeant permeability reduction was noted with CO 2 due to adsorption-induced swelling that is proportional to the amount of gas adsorbed. Helium permeability post CO 2 adsorption decreased by 63% and 31.5% for the 46.3% and 25.4% illite series, respectively. In fact, DCB experiments reveal the potential for CO 2 storage in shale formations with adsorption capacities exceeding that of CH 4 by 4−12 times, depending on the content of TOC and illite. Through a series of low-pressure gas adsorption experiments, it was found that each weight percent increase in TOC has a larger influence on the pore volume and surface area, compared to each weight percent increase in illite content. An ∼3.5 wt % increase in TOC leads to an ∼0.005 cm 3 /g increase in pore volume, whereas it takes a ∼20 wt % increase in illite to achieve a 0.003 cm 3 /g increase. The TOC series pore volume increases by ∼1.4 × 10 −3 cm 3 /g for each weight percent increase in TOC, whereas the illite series pore volume only increases by ∼0.4 × 10 −3 cm 3 /g for each weight percent increase in illite content. The coupled results clearly establish the comparative role of the organic versus inorganic adsorbing components of gas shales while overcoming the material heterogeneity through the investigation of "idealized" compositions.

One potential method for mitigating the impacts of anthropogenic CO2-related climate change is the sequestration of CO2 in depleted geological gas and oil formations, including shale. The accurate characterization of the heterogeneous material properties of shale, including pore capacity, surface area, pore-size distributions, and composition is needed to understand the potential storage capacities of shale formations. Powdered idealized shale samples were created to explore reduction of the complications in characterization of pore capacity that arise from the heterogeneous rock composition and pore sizes ranging over multiple orders of magnitude. The idealized shales were created by mechanically mixing incremental amounts of four essential powdered components by weight and characterized with low pressure gas adsorption/desorption isotherms. The first two components, organic carbon and phyllosilicates (such as clays, micas, and chlorite), have been shown to be the most important components for CO2 uptake in shales. Organic carbon was represented by kerogen isolated from a Silurian shale, and phyllosilicate groups were represented by powdered illite from the Green River shale formation. The remainder of the idealized shale was composed of equal parts by weight of SiO2 to represent quartz and CaCO3 to represent carbonate components. Three idealized sample groups were prepared to be approximately 10, 30, and 55% illite by weight. Each of the sample groups consisted of four samples, incrementing the percent kerogen from 1.5 to 6%. Eagle Ford, Baltic, and Barnett shale sorption measurements were used to validate the idealized sample methodology. The sorption isotherms were measured volumetrically using low pressure N2 (77 K) and Ar (87 K) adsorbates on Quantachrome Autosorb IQ2. Both idealized and validation samples were outgassed using a standardized procedure that produced repeatable results while minimizing changes to the material properties of the shale. The idealized sample results indicated a positive linear correlation with increasing total organic carbon and pore capacity. This work is essential toward the development of predictive models weighted and scaled by the corresponding mineral compositional description of the reservoir.