CT Imaging of Low-Permeability, Dual-Porosity Systems Using High X-ray Contrast Gas

Micro X-ray fluorescence reveals pore space details and spatially-resolved porosity of rock-based microfluidic devices

Characterization of microscopic details of the fabric of mudstones and shales (i.e., structure and composition) is important to understand their storage and transport properties. Current characterization methods struggle to probe reliably multiple scales of interest (e.g., pore and fracture) and measure properties at the finest resolution under representative in situ conditions. Micro X-ray fluorescence (μXRF) is a high-performance imaging technique that produces elemental images at sub-10 μm spatial resolution and could offer insight into a diversity of shale properties, such as mineral composition, porosity, and in situ pressure gradients. This study designed and carried out a porosity mapping protocol using model and real-rock microfluidic devices and contrast fluids. Etched silicon micromodels with real-rock pore network patterns served as ideal models to establish a proof of concept. Measurements were performed on a novel μXRF microscope not powered by synchrotron radiation. We registered the μXRF datasets with the binary rock masks used for micromodel fabrication and applied segmentation algorithms to compare porosities. We assessed expected advantages and limitations through a sensitivity analysis and beam study. μXRF is an important new imaging technique for microfluidic applications.

Combined Effects of CO2 Adsorption-Induced Swelling and Dehydration-Induced Shrinkage on Caprock Sealing Efficiency

Carbon dioxide (CO₂) may infiltrate into the caprock and displace brine water in the caprock layer. This causes two effects: one is the caprock swelling induced by the CO₂ adsorption and the other is the caprock dehydration and shrinkage due to CO₂-brine water two-phase flow. The competition of these two effects challenges the caprock sealing efficiency. To study the evolution mechanism of the caprock properties, a numerical model is first proposed to investigate the combined effects of CO₂ adsorption-induced expansion and dehydration-induced shrinkage on the caprock sealing efficiency. In this model, the caprock matrix is fully saturated by brine water in its initial state and the fracture network has only a brine water-CO₂ two-phase flow. With the diffusion of CO₂ from the fractures into the caprock matrix, the CO₂ sorption and matrix dehydration can alter the permeability of the caprock and affect the entry capillary pressure. Second, this numerical model is validated with a breakthrough test. The effects of the two-phase flow on the water saturation, CO₂ adsorption on the swelling strain, and dehydration on the shrinkage strain are studied, respectively. Third, the permeability evolution mechanism in the CO₂-brine water mixed zone is investigated. The effect of dehydration on the penetration depth is also analyzed. It is found that both the shale matrix dehydration and CO₂ sorption-induced swelling can significantly alter the sealing efficiency of the fractured caprock.

3D porosity structure of the earliest solar system material

Carbonaceous chondrites (CCs) contain the earliest preserved Solar System material, and objects containing this material are targets of numerous sample return missions. Both laboratory and remote sensing data have shown that this material can be highly porous, but the origin and nature of this porosity is currently not well understood. Because the majority of porosity within CCs is submicron to micron in size, previous lab efforts have been restricted by the limited observational scale required to examine this porosity with currently available techniques. Here we present results from a newly developed technique that allows submicron porosity to be examined in 3D within a 12 mm³ volume of CM Murchison. We use X-ray computed tomography combined with the highly attenuating noble gas xenon to characterize porosity well below the spatial resolution of the data (3.01 µm/voxel). This method not only allows examination of submicron porosity within a significantly larger volume than previously possible but also reveals the full three-dimensional porosity structure and pore connectivity. Our data reveal that some fine-grained rims (FGRs) surrounding chondrules have a complex 3D porosity structure, suggesting formation of the FGRs via dust aggregates or variable secondary processing around the rim after accretion.

Chemical and Reactive Transport Processes Associated with Hydraulic Fracturing of Unconventional Oil/Gas Shales

Hydraulic fracturing of unconventional oil/gas shales has changed the energy landscape of the U.S. Recovery of hydrocarbons from tight, hydraulically fractured shales is a highly inefficient process, with estimated recoveries of <25% for natural gas and <5% for oil. This review focuses on the complex chemical interactions of additives in hydraulic fracturing fluid (HFF) with minerals and organic matter in oil/gas shales. These interactions are intended to increase hydrocarbon recovery by increasing porosities and permeabilities of tight shales. However, fluid-shale interactions result in the dissolution of shale minerals and the release and transport of chemical components. They also result in mineral precipitation in the shale matrix, which can reduce permeability, porosity, and hydrocarbon recovery. Competition between mineral dissolution and mineral precipitation processes influences the amounts of oil and gas recovered. We review the temporal/spatial origins and distribution of unconventional oil/gas shales from mudstones and shales, followed by discussion of their global and U.S. distributions and compositional differences from different U.S. sedimentary basins. We discuss the major types of chemical additives in HFF with their intended purposes, including drilling muds. Fracture distribution, porosity, permeability, and the identity and molecular-level speciation of minerals and organic matter in oil/gas shales throughout the hydraulic fracturing process are discussed. Also discussed are analysis methods used in characterizing oil/gas shales before and after hydraulic fracturing, including permeametry and porosimetry measurements, X-ray diffraction/Rietveld refinement, X-ray computed tomography, scanning/transmission electron microscopy, and laboratory- and synchrotron-based imaging/spectroscopic methods. Reactive transport and spatial scaling are discussed in some detail in order to relate fundamental molecular-scale processes to fluid transport. Our review concludes with a discussion of potential environmental impacts of hydraulic fracturing and important knowledge gaps that must be bridged to achieve improved mechanistic understanding of fluid transport in oil/gas shales.

An anisotropic pore-network model to estimate the shale gas permeability

The permeability of shale is a significant and important design parameter for shale gas extraction. The shale gas permeability is usually obtained based on Darcy flow using standard laboratory permeability tests done on core samples, that do not account for different transport mechanisms at high pressures and anisotropic effects in shales due to nano-scale pore structure. In this study, the permeability of shale is predicted using a pore network model. The characteristics of pore structure can be described by specific parameters, including porosity, pore body and pore throat sizes and distributions and coordination numbers. The anisotropy was incorporated into the model using a coordination number ratio, and an algorithm that was developed for connections of pores in the shale formation. By predicting hydraulic connectivity and comparing it with several high-pressure permeability tests, the proposed three-dimensional pore network model was verified. Results show that the prediction from the anisotropic pore network model is closer to the test results than that based on the isotropic pore network model. The predicted permeability values from numerical simulation using anisotropic pore network model for four shales from Qaidam Basin, China are quite similar to those measured from laboratory tests. This study confirmed that the developed anisotropic three-dimensional pore network model could reasonably represent the natural gas flow in the actual shale formation so that it can be used as a prediction tool.

Quantitative imaging of gas adsorption equilibrium and dynamics by X-ray computed tomography

We present the development and application of X-ray Computed Tomography (CT) for the determination of the adsorption properties of microporous adsorbents and the study of breakthrough experiments in a laboratory fixed-bed adsorption column. Using the model system $$\text {CO}_2/\text {helium}$$ CO 2 / helium on activated carbon, equilibrium and dynamic adsorption/desorption measurements by X-ray CT are described, and the results are successfully compared to those obtained from conventional methods, including the application of a one-dimensional dynamic column breakthrough model. The study demonstrates the practical feasibility of applying X-ray CT to measure internal and transient concentration profiles in adsorbent systems on the length-scales from a single adsorbent pellet to a packed column.

A Triple Pore Network Model (T-PNM) for Gas Flow Simulation in Fractured, Micro-porous and Meso-porous Media

In this study, a novel triple pore network model (T-PNM) is introduced which is composed of a single pore network model (PNM) coupled to fractures and micro-porosities. We use two stages of the watershed segmentation algorithm to extract the required data from semi-real micro-tomography images of porous material and build a structural network composed of three conductive elements: meso-pores, micro-pores, and fractures. Gas and liquid flow are simulated on the extracted networks and the calculated permeabilities are compared with dual pore network models (D-PNM) as well as the analytical solutions. It is found that the processes which are more sensitive to the surface features of material, should be simulated using a T-PNM that considers the effect of micro-porosities on overall process of flow in tight pores. We found that, for gas flow in tight pores where the close contact of gas with the surface of solid walls makes Knudsen diffusion and gas slippage significant, T-PNM provides more accurate solution compared to D-PNM. Within the tested range of operational conditions, we recorded between 10 and 50% relative error in gas permeabilities of carbonate porous rocks if micro-porosities are dismissed in the presence of fractures.

On the challenges of greyscale-based quantifications using X-ray computed microtomography

For X-ray computed microtomography (μ-CT) images of porous rocks where the grains and pores are not fully resolved, the greyscale values of each voxel can be used for quantitative calculations. This study addresses the challenges that arise with greyscale-based quantifications by conducting experiments designed to investigate the sources of error/uncertainty. We conduct greyscale-based calculations of porosity, concentration and diffusivity from various μ-CT experiments using a Bentheimer sandstone sample. The dry sandstone is imaged overtime to test the variation of greyscale values over sequential scans due to instrumentation stability. The sandstone is then imaged in a dry and contrast-agent saturated state at low resolution to determine a porosity map, which is compared to a porosity map derived from segmented high-resolution data. Then the linearity of the relationship between the concentration of a contrast agent and its corresponding attenuation coefficient is tested by imaging various solutions of known concentration. Lastly, a diffusion experiment is imaged at low resolution under dynamic conditions to determine local diffusivity values for the sandstone, which is compared to values derived from direct pore-scale simulations using high-resolution data. Overall, we identify the main errors associated with greyscale-based quantification and provide practical suggestions to alleviate these issues. LAY DESCRIPTION: X-ray computed microtomography (CT) imaging has become an important way to study the pore space of a porous medium. Using segmented images, we can build 3D pore space models for porous media and characterize the morphology and/or run simulations on the models. So, image segmentation is a critical image processing step. However, for low resolution images where image segmentation is not possible, grayscales are directly used for quantifications such as porosity and concentration calculations. Although these types of calculations have been widely accepted and used, the uncertainties and errors associated with grayscale-based quantifications are not fully discussed. Here we specifically design experiments with X-ray CT imaging to address the challenges that arise in grayscale-based quantifications. For instance, in order to validate porosity calculation results from low resolution images (with the help of high attenuating tracer), high resolution images are also acquired, which serve as a benchmark. The errors associated with concentration calculation using grayscale values are also discussed. In addition, numerical simulations using grayscale values are performed on a diffusion experiment images with X-ray CT. The problems that arise in dynamic imaging and the subsequent numerical simulations are discussed. The experiments, calculations and discussions provide a more comprehensive understanding on grayscale-based quantifications and aid in designing better X-ray CT experiments.

An experimental platform for triaxial high-pressure/high-temperature testing of rocks using computed tomography

A conventional high-pressure/high-temperature experimental apparatus for combined geomechanical and flow-through testing of rocks is not X-ray compatible. Additionally, current X-ray transparent systems for computed tomography (CT) of cm-sized samples are limited to design temperatures below 180 °C. We describe a novel, high-temperature (>400 °C), high-pressure (>2000 psi/>13.8 MPa confining, >10 000 psi/>68.9 MPa vertical load) triaxial core holder suitable for X-ray CT scanning. The new triaxial system permits time-lapse imaging to capture the role of effective stress on fluid distribution and porous medium mechanics. System capabilities are demonstrated using ultimate compressive strength (UCS) tests of Castlegate sandstone. In this case, flooding the porous medium with a radio-opaque gas such as krypton before and after the UCS test improves the discrimination of rock features such as fractures. The results of high-temperature tests are also presented. A Uintah Basin sample of immature oil shale is heated from room temperature to 459 °C under uniaxial compression. The sample contains kerogen that pyrolyzes as temperature rises, releasing hydrocarbons. Imaging reveals the formation of stress bands as well as the evolution and connectivity of the fracture network within the sample as a function of time.

Pore-Scale Simulation and Sensitivity Analysis of Apparent Gas Permeability in Shale Matrix

Extremely low permeability due to nano-scale pores is a distinctive feature of gas transport in a shale matrix. The permeability of shale depends on pore pressure, porosity, pore throat size and gas type. The pore network model is a practical way to explain the macro flow behavior of porous media from a microscopic point of view. In this research, gas flow in a shale matrix is simulated using a previously developed three-dimensional pore network model that includes typical bimodal pore size distribution, anisotropy and low connectivity of the pore structure in shale. The apparent gas permeability of shale matrix was calculated under different reservoir pressures corresponding to different gas exploitation stages. Results indicate that gas permeability is strongly related to reservoir gas pressure, and hence the apparent permeability is not a unique value during the shale gas exploitation, and simulations suggested that a constant permeability for continuum-scale simulation is not accurate. Hence, the reservoir pressures of different shale gas exploitations should be considered. In addition, a sensitivity analysis was also performed to determine the contributions to apparent permeability of a shale matrix from petro-physical properties of shale such as pore throat size and porosity. Finally, the impact of connectivity of nano-scale pores on shale gas flux was analyzed. These results would provide an insight into understanding nano/micro scale flows of shale gas in the shale matrix.

Micro/Nano-pore Network Analysis of Gas Flow in Shale Matrix

The gas flow in shale matrix is of great research interests for optimized shale gas extraction. The gas flow in the nano-scale pore may fall in flow regimes such as viscous flow, slip flow and Knudsen diffusion. A 3-dimensional nano-scale pore network model was developed to simulate dynamic gas flow, and to describe the transient properties of flow regimes. The proposed pore network model accounts for the various size distributions and low connectivity of shale pores. The pore size, pore throat size and coordination number obey normal distribution, and the average values can be obtained from shale reservoir data. The gas flow regimes were simulated using an extracted pore network backbone. The numerical results show that apparent permeability is strongly dependent on pore pressure in the reservoir and pore throat size, which is overestimated by low-pressure laboratory tests. With the decrease of reservoir pressure, viscous flow is weakening, then slip flow and Knudsen diffusion are gradually becoming dominant flow regimes. The fingering phenomenon can be predicted by micro/nano-pore network for gas flow, which provides an effective way to capture heterogeneity of shale gas reservoir.

Functionalization of micromodels with kaolinite for investigation of low salinity oil-recovery processes

Sandstone formations are ubiquitous in both aquifers and petroleum reservoirs, of which clay is a major constituent. The release of clay particles from pore surfaces as a result of reduced injection fluid salinity can greatly modify the recovery of hydrocarbons from subsurface formations by shifting the wettability properties of the rock. In this paper we demonstrate a microfluidic approach whereby kaolinite is deposited into a two-dimensional microfluidic network (micromodel) to enable direct pore-scale, real-time visualization of fluid-solid interactions with representative pore-geometry and realistic surface interactions between the reservoir fluids and the formation rock. Structural characterization of deposited kaolinite particles agrees well with natural modes of occurrence in Berea sandstones; hence, the clay deposition method developed in this work is validated. Specifically, more than 90% of the deposited clay particles formed pore-lining structures and the remainder formed pore bridging structures. Further, regions of highly concentrated clay deposition likely leading to so-called Dalmatian wetting properties were found throughout the micromodel. Two post-deposition treatments are described whereby clay is adhered to the silicon surface reversibly and irreversibly resulting in microfluidic systems that are amenable to studies on (i) the fundamental mechanisms governing the increased oil recovery during low salinity waterfloods and (ii) the effect of a mixed-wet surface on oil recovery, respectively. The reversibly functionalized platform is used to determine the conditions at which stably adhered clay particles detach. Specifically, injection brine salinity below 6000 ppm of NaCl induced kaolinite particle release from the silicon surface. Furthermore, when applied to an aged system with crude oil, the low salinity waterflood recovered an additional 14% of the original oil in place compared to waterflooding with the formation brine.

Multidimensional quantitative imaging of gas adsorption in nanoporous solids

X-ray computed tomography is applied to image gas adsorption in nanoporous solids. The equations are developed to calculate rigorous measures of adsorption, such as the excess adsorbed amount, by applying a dual-scanning technique. This approach is validated by considering the CO2/13X zeolite system in a fixed-bed adsorber, and multidimensional patterns are obtained of key characteristic properties, such as bed porosity, excess adsorption, and density of the adsorbed phase. The quantification of the spatial variability of the adsorbed amount within the system represents a major novelty with regards to conventional techniques. The ability to quantify adsorption with such a level of observational detail discloses unparalleled opportunities to interrogate and revisit adsorption processes in porous media.