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Summary Source rocks (oil shale) were matured artificially via pyrolysis under geologically realistic triaxial stresses using a unique coreholder that is compatible with X-ray computed tomography (CT) scanning. This study focuses on characterization of porosity and permeability as well as the evolution of shale fabric during pyrolysis. Experiments were conducted using 1-in. diameter vertical and horizontal core samples from the Green River Formation. Prior to pyrolysis, the properties of the source rock were characterized [e.g., porosity, bulk density, mineralogy, and total organic carbon (TOC)]. Samples were then heated from room temperature to 350°C under a nitrogen environment to obtain conversion of organic matter (OM) to oil and gas via pyrolysis. Porosity and permeability after maturation were measured. Micro-CT visualization was applied to investigate the fracture network developed throughout the core. Scanning electron microscopy (SEM) images were also used to compare the shale fabric and porosity evolution (pre- to post-maturation) at greater resolution. In-situ observations reveal a decrease in the average CT number (i.e., density) within some volumetric regions of the cores after maturation. In these regions, OM (kerogen and bitumen) was converted into hydrocarbons. Changes in the source rock depend on the original TOC fraction, hydrogen index (HI), and temperature. The permeability prior to pyrolysis for vertical samples is in the undetectable to nanodarcy range. The permeability of all cores increased to the microdarcy range post-maturation. In particular, the permeability of the horizontal sample increased from 0.14 to 50 µd. This improvement in permeability occurred due to the generation of open porosity and fractures (dilation, generation, and/or drainage). Additionally, the porosity after Soxhlet extraction increased proportionally by 20% from pre- to post-pyrolysis depending on pyrolysis time and TOC fraction. Longitudinal deformation depends on the orientation of the sample with respect to the triaxial stress during pyrolysis. The deformation of vertically oriented samples with isostress conditions is larger than that of horizontally oriented samples with isostrain. The measured 3D in-situ porosity distribution indicates that OM has transformed into hydrocarbons by pyrolysis. The development of a fracture and matrix porosity system under stress provides an explanation for transport of hydrocarbon away from its point of origin.

The interaction of reactive fracture fluid with host shale and formation water plays an important role on fractured reservoir productivity. This study explores the prominent impacts of shale−fluid reactions on flow properties using representative core-flood experiments under confining stress. Alteration of shale is monitored using time-lapse X-ray computed tomography (CT), microCT (μCT) of samples preand post-reaction, and scanning electron microscopy (SEM). The imaging approach is multiscale from nm's to cm's. The samples are clayrich and partially fractured Marcellus outcrop and carbonate-rich MSEEL (Marcellus Shale Energy and Environmental Laboratory) downhole endmembers. Both samples have distinct microcracks for probing reactive transport in fractures communicating with matrices. A reduction in krypton-accessible CT porosity and liquid permeability was observed for both samples after fracture fluid exposure. Based on SEM-EDS surface analysis, an iron-bearing precipitate formed on and near fracture openings and in the shale matrix of the Marcellus outcrop indicating partial dissolution of pyrite and/or ferruginous dolomite followed by precipitation of iron (hydro)oxide. The compiled images reveal fracture filling with migrated and/or precipitated fine particles. Significant barite scale growth was detected on the reacted MSEEL surfaces together with halite and other (hydro)oxide precipitates resulting from geochemical reactions between the basin-specific injectants and shale minerals. The MSEEL sample experienced substantial calcite dissolution and a corresponding decrease in its bulk density and microcrack openings. Experimental results presented here indicate the significance of fracture fluid composition optimization based on intrinsic shale and resident brine chemistries.

Silicon-based microfluidic devices, so-called micromodels in this application, are particularly useful laboratory tools for the direct visualization of fluid flow revealing pore-scale mechanisms controlling flow and transport phenomena in natural porous media. Current microfluidic devices with uniform etched depths, however, are limited when representing complex geometries such as the multiple-scale pore sizes common in carbonate rocks. In this study, we successfully developed optimized sequential photolithography to etch micropores (1.5 to 21 μm width) less deeply than the depth of wider macropores (>21 μm width) to improve the structural realism of an existing single-depth micromodel with a carbonate-derived pore structure. Surface profilimetry illustrates the configuration of the dual-depth dual-porosity micromodel and is used to estimate the corresponding pore volume change for the dual-depth micromodel compared to the equivalent uniform- or single-depth model. The flow characteristics of the dual-depth dual-porosity micromodel were characterized using micro-particle image velocimetry (μ-PIV), relative permeability measurements, and pore-scale observations during imbibition and drainage processes. The μ-PIV technique provides insights into the fluid dynamics within microfluidic channels and relevant fluid velocities controlled predominantly by changes in etching depth. In addition, the reduction of end-point relative permeability for both oil and water in the new dual-depth dual-porosity micromodel compared to the equivalent single-depth micromodel implies more realistic capillary forces occurring in the new dual-depth micromodel. Throughout the imbibition and drainage experiments, the flow behaviors of single- and dual-depth micromodels are further differentiated using direct visualization of the trapped non-wetting phase and the preferential mobilization of the wetting phase in the dual-depth micromodel. The visual observations agree with the relative permeability results. These findings indicate that dual-porosity and dual-depth micromodels have enhanced physical realism that is pertinent to oil recovery processes in complex porous media.

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.