Porosity and permeability are the key factors in assessing the hydrocarbon productivity of unconventional (shale) reservoirs, which are complex in nature due to their heterogeneous mineralogy and poorly connected nano-and micro-pore systems. Experimental efforts to measure these petrophysical properties posse many limitations, because they often take weeks to complete and are difficult to reproduce. Alternatively, numerical simulations can be conducted in digital rock 3D models reconstructed from image datasets acquired via e.g., nanoscale-resolution focused ion beam-scanning electron microscopy (FIB-SEM) nano-tomography. In this study, impact of reservoir confinement (stress) on porosity and permeability of shales was investigated using two digital rock 3D models, which represented nanoporous organic/mineral microstructure of the Marcellus Shale. Five stress scenarios were simulated for different depths (2,000-6,000 feet) within the production interval of a typical oil/gas reservoir within the Marcellus Shale play. Porosity and permeability of the pre-and post-compression digital rock 3D models were calculated and compared. A minimal effect of stress on porosity and permeability was observed in both 3D models. These results have direct implications in determining the oil-/gas-in-place and assessing the production potential of a shale reservoir under various stress conditions.
Carbonate rocks have particularly complex and multiscale pore systems which are weakly understood. In this study we use combined experimental, modelling, and pore space generation methods to tackle the impact of micro-porosity on the bulk flow properties of Estaillades limestone. First, a nano-core from a microporous grain of Estaillades Limestone was scanned using x-ray nano tomography (nano-XRM). The information from the nano-XRM scan was then used as input into an object-based pore network generator, on which permeability fields were simulated for a range of porosities, creating a synthetic Kozeny-Carman porosity-permeability relationship targeted for the specific micro porous system present in Estaillades. We found a good match between experimental and simulated Mercury Intrusion Capillary Pressure (MICP) range in the imaged geometry and a good match between the imaged and object generated permeabilities and MICP. A micro-core of Estaillades was then scanned using x-ray microtomography (μCT), the differential pressure was measured during single phase flow, and the rock was flooded with highly doped brine to differentiate connected from unconnected micro-porosity. The differential contrast between the dry and doped images was used to assign a porosity to each voxel of connected micro-porosity. The flow through the pore space was then solved using a Stokes-Brinkman solver while a second segmented image with no micro-porosity was solved a Stokes solver. The differences between the measured permeability and the two computed permeabilities was evaluated. We found that there was good agreement between both the computed permeability of the Stokes and Stokes-Brinkman simulation with the measured permeability. However, there was considerable differences in the velocity fields with the Stokes-Brinkman simulation capturing stagnant regions of the pore space that were not present in the Stokes simulations. Additionally, we investigated the implications of including micro-porosity in estimations of relative permeability. Nitrogen was experimentally co-injected through the core with doped brine at a 50% fractional flow and imaged to the two-phase effective permeability. This experimental measurement was compared with the numerical permeability simulated using both Stokes and Stokes-Brinkman models for several saturation points along a synthetic MICP injection curve. We found that the Stokes simulation was not able to predict relative permeability with this method due to the major flow paths in the macro-porosity being impeded by the injected non-wetting phase. The Stokes-Brinkman simulations, however, allowed flow in the microporous regions around these blocked flow paths and was able to achieve a relative permeability prediction that was a reasonable match to the experimental measurement. This method could be used to predict relative permeability in water wet pore-structures with high micro-porosity.
Carbonate rocks have multiscale pore systems that are weakly understood. In this study, we use combined experimental, modeling, and pore space generation methods to tackle the impact of microporosity on the flow properties of Estaillades limestone. First, a nano-core from a microporous grain of Estaillades limestone was scanned using nanotomography (nano-XRM). The information from the nano-XRM scan was then used as input into an object-based pore network generator, on which permeability fields were simulated for a range of porosities, creating a synthetic Kozeny–Carman porosity–permeability relationship targeted for the specific microporous system present in Estaillades. We found a good match between the experimental and simulated Mercury Intrusion Capillary Pressure (MICP) range in the imaged geometry and a good match between the imaged and object-generated permeabilities and MICP. A micro-core of Estaillades was then scanned using X-ray microtomography (μCT), the differential pressure was measured during single-phase flow, and the rock was flooded with doped brine. The contrast between the images was used to assign a porosity to each voxel of connected microporosity. The flow through the pore space was solved using the Stokes–Brinkman (S–B) and Stokes-only solvers, and the differences between the measured permeability and computed permeabilities were evaluated. An agreement was seen between the computed permeability of the Stokes and S–B simulation with the measured permeability. However, the velocity fields with the S–B simulation captured stagnant regions of the pore space that were not present in the Stokes simulations. Additionally, we investigated the implications of including microporosity in the estimation of relative permeability. Nitrogen was experimentally co-injected through the core with doped brine at a 50% fractional flow and imaged to capture the two-phase effective permeability and was compared with the simulated numerical permeability. The Stokes simulation was not able to predict relative permeability with this method due to the major flow paths in the macroporosity being impeded by the injected non-wetting phase. The S–B simulations, however, allowed flow in the microporous regions around these blocked flow paths and were able to achieve a relative permeability prediction that was a reasonable match to the experimental measurement.
Most commercially used electrode materials contract and expand upon cycling. This change in volume influences the microstructure of the cell stack, which in turn impacts a range of performance parameters. Since direct observation of these microstructural changes with operando experiments is challenging and time intensive, a simulation tool that takes a real or artificially generated 3D microstructure and captures the volumetric changes in a cell during cycling would be valuable to enable rapid understanding of the impact of material choice, electrode and cell design, and operating conditions on the microstructural changes and identification of sources of mechanically-driven cell aging. Here, we report the development and verification of such a 3D electrochemical-mechanical tool, and provide an example use-case. We validate the tool by simulating the microstructural evolution of a graphite anode and a Li(Ni,Mn,Co)O2 cathode during cycling and comparing the results to x-ray tomography datasets of these electrodes taken during cycling. As an example use case for such a simulation tool, we explore how different volumetric expansion behaviors of the cathode material impact strain in the cell stack, illustrating how the material selection and its operation impact the mechanical behavior inside a cell.
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