The complexity of unconventional rock systems is expressed both in the compositional variance of the microstructure and the extensive heterogeneity of the pore space. Visualizing and quantifying the microstructure of oil shale before and after pyrolysis permits a more accurate determination of petrophysical properties which are important in modeling hydrocarbon production potential. We characterize the microstructural heterogeneity of oil shale using X-ray micro-tomography (µCT), automated ultra-high resolution scanning electron microscopy (SEM), MAPS Mineralogy (Modular Automated Processing System) and Focused Ion Beam Scanning Electron Microscopy (FIB-SEM). The organic-rich Eocene Green River (Mahogany zone) oil shale is characterized using a multi-scale multi-dimensional workflow both before and after pyrolysis. Observations in 2-D and 3-D and across nm-µm-mm length scales demonstrate both heterogeneity and anisotropy at every scale. Image acquisition and analysis using µCT and SEM reveal a microstructure of alternating kerogen-rich laminations interbedded with layers of fine-grained inorganic minerals. MAPS Mineralogy combined with ultrafast measurements reveal mineralogic textures dominated by dolomite, calcite, K-feldspar, quartz, pyrite and illitic clays along with their spatial distribution, augmenting conventional mineral analysis. From high resolution Backscattered electron (BSE) images, intra-organic, inter-organic-mineral, intra- and inter-mineral pores are observed with varying sizes and geometries. By using FIB milling and SEM imaging sequentially and repetitively, 3-D data sets were reconstructed. By setting 3-D gradient and marker-based watershed transforms, the organic matter, minerals and pore phases (including pore-back artifacts) were segmented and visualized and the pore-size distribution was computed. Following pyrolysis, fractures from the mm-to-µm scales were observed with preferential propagation along the kerogen-rich laminations and coalescence leading to an interconnected fracture network. The application of these techniques to worldwide oil shale deposits will allow significant insights into estimating mechanical and chemical proprieties of oil shale formations for modeling and designing oil shale pyrolysis processes

Understanding the pore-scale dynamics of two-phase fluid flow in permeable media is important in many processes such as water infiltration in soils, oil recovery, and geo-sequestration of CO₂. The two most important processes that compete during the displacement of a non-wetting fluid by a wetting fluid are pore-filling or piston-like displacement and snap-off; this latter process can lead to trapping of the non-wetting phase. We present a three-dimensional dynamic visualization study using fast synchrotron X-ray micro-tomography to provide new insights into these processes by conducting a time-resolved pore-by-pore analysis of the local curvature and capillary pressure. We show that the time-scales of interface movement and brine layer swelling leading to snap-off are several minutes, orders of magnitude slower than observed for Haines jumps in drainage. The local capillary pressure increases rapidly after snap-off as the trapped phase finds a position that is a new local energy minimum. However, the pressure change is less dramatic than that observed during drainage. We also show that the brine-oil interface jumps from pore-to-pore during imbibition at an approximately constant local capillary pressure, with an event size of the order of an average pore size, again much smaller than the large bursts seen during drainage.

The microstructural evaluation of oil shale is challenging which demands the use of several complementary methods. In particular, an improved insight into the pore network structure and connectivity before, during, and after oil shale pyrolysis is critical to understanding hydrocarbon flow behavior and enhancing recovery. In this experimental study, bulk analyses are combined with traditional and advanced imaging methods to comprehensively characterize the internal microstructure and chemical composition of the world’s richest oil shale deposit, the Green River Formation (Mahogany Zone). Image analysis in two dimensions (2-D) using optical and scanning electron microscopy (SEM), and in three dimensions (3-D) using X-ray microtomography (µCT) reveals a complex and variable fine-grained microstructure dominated by organic-rich parallel laminations of the order of 10 µm thick which are tightly bound in a highly calcareous and heterogeneous mineral matrix. We also report the results of a detailed µCT study of the Mahogany oil shale with increasing pyrolysis temperature (300–500 °C) at 12 µm and 2 µm voxel sizes. The physical transformation of the internal microstructure and evolution of pore space during the thermal conversion of kerogen in oil shale to produce hydrocarbon products was characterized. The 3-D volumes of pyrolyzed oil shale were reconstructed and image processed to visualize and quantify the volume and connectivity of the pore space. The results show a significant increase in anisotropic porosity associated with pyrolysis between 400 and 500 °C with the formation of micro-scale connected pore channels developing principally along the kerogen-rich lamellar structures. Given the complexity and heterogeneity of oil shale, we also characterize the representative size at which porosity remains constant. Our results provide a direct observation of pore and microfracture development during oil shale pyrolysis and the petrophysical measurements from this study serve as valuable input parameters to modeling oil shale pyrolysis processes

High-resolution x-ray imaging was used in combination with differential pressure measurements to measure relative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on a sample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil to alter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flow rate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, x-ray tomographic images were taken. The images were used to compute saturation, interfacial area, curvature, and contact angle. From this information relative permeability and capillary pressure were determined as functions of saturation. We compare our results with a previously published experiment under water-wet conditions. The oil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, of approximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock. The capillary pressure was slightly negative and 10 times smaller in magnitude than for the water-wet rock, and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area was also largely constant in this saturation range. The measured static contact angles had an average of ${80}^{\circ }$ with a standard deviation of ${17}^{\circ }$. We observed that the oil-brine interfaces were not flat, as may be expected for a very low mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. These interfaces were approximately minimal surfaces, which implies well-connected phases. Saddle-shaped menisci swept through the pore space at a constant capillary pressure and with an almost fixed area, removing most of the oil.

There are a number of challenges associated with the determination of relative permeability and capillary pressure. It is difficult to measure both parameters simultaneously on the same sample using conventional methods. Instead, separate measurements are made on different samples, usually with different flooding protocols. Hence, it is not certain that the pore structure and displacement processes used to determine relative permeability are the same as those when capillary pressure was measured. Moreover, at present, we do not use pore‐scale information from high‐resolution imaging to inform multiphase flow properties directly. We introduce a method using pore‐scale imaging to determine capillary pressure from local interfacial curvature. This, in combination with pressure drop measurements, allows both relative permeabilities and capillary pressure to be determined during steady state coinjection of two phases through the core. A steady state waterflood experiment was performed in a Bentheimer sandstone, where decalin and brine were simultaneously injected through the core at increasing brine fractional flows from 0 to 1. The local saturation and the curvature of the oil‐brine interface were determined. Using the Young‐Laplace law, the curvature was related to a local capillary pressure. There was a detectable gradient in both saturation and capillary pressure along the flow direction. The relative permeability was determined from the experimentally measured pressure drop and average saturation obtained by imaging. An analytical correction to the brine relative permeability could be made using the capillary pressure gradient. The results for both relative permeability and capillary pressure are consistent with previous literature measurements on larger samples.