Fluid Flow and Microstructural Properties of Gas Shales

In recent years, the production of natural gas and oil from shale has had a dramatic impact on the gas and oil industries, with shale gas plays the biggest source of natural gas in, for example, the USA (US Energy Information Administration, 2016). There has been a consequential and considerable increase in demand for better characterization of shale gas plays. However, cost-effective shale gas production requires detailed knowledge of the petrophysical characteristics of the shale from which the gas is extracted. Parameters such as the kerogen fraction, pore size distributions, porosity, permeability, the frackability of the rock and the degree to which natural fracturing already occurs are required in order to be able to estimate potential gas reserves and how easily it can be extracted. Characterization of shale gas plays is challenging because of they tend to be both tight and heterogeneous due to the mechanisms by which they are deposited and subsequent diagenetic processes and also due to the small size of the pores and low permeability, porosity. SEM imaging has confirmed the tremendous physical heterogeneity of shale gas plays ( Charmers et al., 2009; Loucks et al., 2009; Wang et al., 2009; Ambrose et al., 2010; Curtis et al., 2010). Strong characterization of a reservoir necessitates detailed knowledge of, for example, flow capabilities, permeability, porosity, pore connectivity and storage. Knowledge of these characteristics will help to determine flow capacity, how to control gas extraction, and hydrocarbon storage. Permeability and porosity are two principal parameters required for accurate assessment of gas-/oil-in-place to forecast production. The measurement of porosity is considered to be relatively straightforward; numerous tests have been used successfully, including helium porosity. On the other hand, the measurement of permeability is more challenging. For instance, steady-state measurements which have been used successfully with more typical reservoirs are not easy to use with shale samples, for which more complex, unsteady-state methods including pulse-decay are required (Javadpour and Ettehadtavakkoli 2015). Measurement of low permeability’s using pulse-decay is considered a good method for measurement of permeability of shale rock samples (Jones, 1997) but has a number of drawbacks such as being relatively expensive, and results can depend on sample size. Thus, other methods are required for confirmatory analysis of permeability and pore systems in shale rock samples

Nano-Scale Characterization of Particulate Iron Pyrite Morphology in Shale

This study analyzes the morphology of iron pyrite particles within a shale sample captured using nano-computed tomography (Nano-CT). The complex, framboidal morphology of the iron pyrite particles is characterized using various metrics, and comparisons are drawn on their effectiveness to quantify their observed morphological characteristics. Then, simplified representations of selected iron pyrite particles are generated to facilitate a sensitivity analysis of the effect of imaging resolution on morphological parameters of particle form. A discussion is developed on the required number of pixels per particle diameter for particle shape characterization. It is shown that shape indices that rely on the simplified main particle dimensions can be accurately calculated even for low fidelity levels of 10 pixels per particle diameter. More complex shape indices that use vertices, volume, and surface area, are more sensitive to image resolution, even for 40 pixels per particle diameter

Integration of Multiscale Imaging of Nanoscale Pore Microstructures in Gas Shales

Quantification of the microstructures of shales is difficult due to their complexity which extends across many orders of magnitude of scale. Nevertheless, shale microstructures are extremely important, not only as shale gas resources but also as cap rocks in CCS resources, in geothermal reservoirs, and as a host to the long-term storage of radioactive materials. In this work, we have performed ultrahigh-resolution CT imaging (nano-CT), mercury injection porosimetry (MIP), and nitrogen adsorption experiments on a sample of gas shale for which we already have focused ion beam scanning electron microscopy (FIB-SEM) and high-resolution CT (micro-CT) data sets. The combination of these data sets has allowed us to examine the microstructure of the shale in unprecedented depth across a wide range of scales (from about 20 nm to 0.5 mm). Overall, the sample shows a porosity of 0.67 ± 0.009% from the nano-CT data, 0.0235 ± 0.003% from nitrogen adsorption, and 0.60 ± 0.07% from MIP, which compare with 0.10 ± 0.01%, 0.52 ± 0.05%, and 0.94 ± 0.09% from three FIB-SEM measurements and 0.06 ± 0.008% from one micro-CT measurement. The data vary due to the different scales at which each technique interrogates the rock and whether the pores are openly accessible (especially in the case of the nitrogen adsorption value). The measured kerogen fraction is 32.4 ± 1.45% from nano-CT compared with 34.8 ± 1.74%, 38.2 ± 1.91%, 41.4 ± 2.07%, and 44.5 ± 2.22% for three FIB-SEM and one micro-CT measurement. The pore size imaged by nano-CT ranged between 100 and 5000 nm, while the corresponding ranges were between 3 and 2000 nm for MIP analysis and between 2 and 90 nm for N2 adsorption. The distribution of pore aspect ratio and scale-invariant pore surface area to volume ratio (σ) as well as the calculated permeability shows the sample to have a high shale gas potential. Aspect ratios indicate that most of the pores that contribute significantly to pore volume are oblate, which is confirmed by the range of σ (3–13). Oblate pores have greater potential for interacting with other pores compared to equant and needle-shaped prolate pores as well optimizing surface area for gas to desorb from the kerogen into the pores. Permeability essays provide 2.61 ± 0.42 nD from the nano-CT data, 2.65 ± 0.45 nD from MIP, and (5.07 ± 0.02) × 10–4 nD from nitrogen adsorption, which are consistent with expectations for generic gas shales (i.e., tens of nD) and the measurements made previously on the same sample using FIB-SEM and micro-CT imaging techniques

Ultrahigh-Resolution 3D Imaging for Quantifying the Pore Nanostructure of Shale and Predicting Gas Transport

The pore and fracture microstructures are key to understanding gas flow in shales. The experimental determination of these microstructures is dependent on the measurement technique employed and its resolution. High-resolution three-dimensional imaging techniques coupled with image analysis and numerical simulations have been employed to characterize the petrophysical properties of shale samples. In this work, our particular focus is on using the Nano-CT and focused ion beam scanning electron microscopy (FIB-SEM) techniques at the same location in a shale rock sample to investigate the effect of their different resolutions and fields of view on the resulting imaged nanopore structure, as well as to determine any differences in the consequent measurements of the shale petrophysical properties. These petrophysical properties include porosity, permeability, pore volume and size distribution, the pore aspect ratio, the surface area to volume, and pore connectivity. The reconstructed matrix, kerogen, and pore space volumes from each approach showed significant scale-dependent differences in the microstructure. The shale sample displayed a high kerogen content with high connectivity. Porosity from the reconstructed shale volumes was observed to be 0.43 and 0.7% for FIB-SEM and Nano-CT approaches, respectively. The pore volume, size, surface area to volume ratio, and two orthogonal pore aspect ratio distributions have also been determined from the reconstructed image data by three-dimensional (3D) image analysis. These data show that voids within the rock are oblate at all scales. Permeabilities have been calculated from both the FIB-SEM and Nano-CT images and fall in the range of 2.55–9.92 nD. A simulation has also been produced based on the permeability calculation and parameters from the image analysis. The results of the simulation show connectivity in the x-, y-, and z-directions for both the FIB-SEM and Nano-CT images, with very low connectivity in the x-direction but higher connectivity in the y- and z-directions

Integration of Multi-Scale Imaging of Nanoscale Pore Microstructures in Gas Shales

Quantification of the microstructures of shales is difficult due to their complexity which extends across many orders of magnitude of scale. Nevertheless, shale microstructures are extremely important, not only as shale gas resources but also as cap rocks in CCS resources, in geothermal reservoirs, and as a host to the long-term storage of radioactive materials. In this work, we have performed ultrahigh-resolution CT imaging (nano-CT), mercury injection porosimetry (MIP), and nitrogen adsorption experiments on a sample of gas shale for which we already have focused ion beam scanning electron microscopy (FIB-SEM) and high-resolution CT (micro-CT) data sets. The combination of these data sets has allowed us to examine the microstructure of the shale in unprecedented depth across a wide range of scales (from about 20 nm to 0.5 mm). Overall, the sample shows a porosity of 0.67 ± 0.009% from the nano-CT data, 0.0235 ± 0.003% from nitrogen adsorption, and 0.60 ± 0.07% from MIP, which compare with 0.10 ± 0.01%, 0.52 ± 0.05%, and 0.94 ± 0.09% from three FIB-SEM measurements and 0.06 ± 0.008% from one micro-CT measurement. The data vary due to the different scales at which each technique interrogates the rock and whether the pores are openly accessible (especially in the case of the nitrogen adsorption value). The measured kerogen fraction is 32.4 ± 1.45% from nano-CT compared with 34.8 ± 1.74%, 38.2 ± 1.91%, 41.4 ± 2.07%, and 44.5 ± 2.22% for three FIB-SEM and one micro-CT measurement. The pore size imaged by nano-CT ranged between 100 and 5000 nm, while the corresponding ranges were between 3 and 2000 nm for MIP analysis and between 2 and 90 nm for N2 adsorption. The distribution of pore aspect ratio and scale-invariant pore surface area to volume ratio (σ) as well as the calculated permeability shows the sample to have a high shale gas potential. Aspect ratios indicate that most of the pores that contribute significantly to pore volume are oblate, which is confirmed by the range of σ (3–13). Oblate pores have greater potential for interacting with other pores compared to equant and needle-shaped prolate pores as well optimizing surface area for gas to desorb from the kerogen into the pores. Permeability essays provide 2.61 ± 0.42 nD from the nano-CT data, 2.65 ± 0.45 nD from MIP, and (5.07 ± 0.02) × 10–4 nD from nitrogen adsorption, which are consistent with expectations for generic gas shales (i.e., tens of nD) and the measurements made previously on the same sample using FIB-SEM and micro-CT imaging techniques

Micro- and Nano-Scale Pore Structure in Gas Shale Using Xμ-CT and FIB-SEM Techniques

Shale is a complex rock composed of a complex mixture of matrix minerals and kerogen and having a complex pore microstructure. The pore microstructure is highly dependent upon the scale at which it is considered. Such a microstructure is important for the assessment of the potential of gas shales based on the connectivity and pores at each scale and the ability of the rock to be hydraulically fractured. In this work, the three-dimensional (3D) structure of Bowland shale has been investigated at both microscopic and nanoscopic scales on the same sample for the first time using (i) a combination of serial sectioning, using focused ion beam (FIB) milling and scanning electron microscopy (SEM), and (ii) X-ray micro-computed tomography (Xμ-CT). The reconstructed matrix, kerogen, and pore space volumes from each approach showed significant scale-dependent differences in the microstructure. The shale samples displayed a high kerogen content with high connectivity. Porosity in the shale rock sample was observed to be prevalent in either the inorganic matrix, the kerogen, or both. Furthermore, the porosity from the reconstructed shale volumes was found to vary with locations, as sampled by FIB-SEM, within the shale samples taken for Xμ-CT. Pore volume, scale invariant surface area to volume ratios, and two orthogonal pore aspect ratio distributions were extracted from the reconstructed image data by 3D image analysis. These data show that voids within the rock are oblate at all scales. However, the smaller pores visible by FIB-SEM present higher scale invariant surface area to volume ratios, indicating that they are more likely to interlink the larger pores visible by Xμ-CT and form a small scale but highly connected pore network for fluid flow. Permeabilities have been calculated from both the FIB-SEM and Xμ-CT images and fall in the range 2.98 to 150 nD, broadly agreeing with experimental determinations from another author