"Determining shale gas petrophysical properties is the cornerstone to any reservoir-management practice. Hitherto, conventional core analyses are inadequate to attain the petrophysical properties of shale gas at submicron-scale. This study combines interdisciplinary techniques from material science, petrophysics, and geochemistry to characterize different shale gas samples from North America including Utica, Haynesville and Fayetteville shale gas plays. Submicron pore structure, clay mineralogy, wettability and organic matter maturation were investigated to evaluate the petrophysical properties of shale gas rocks and to determine the impact of organic and inorganic matters on wettability alteration for different fracturing fluids on shale gas rocks. High pressure (up to 60,000 psi) mercury porosimetry analysis (MICP) determined the pore size distributions. A robust detailed sequential milling and imaging procedure using dual beam (SEM/FIB) instrument was implemented successfully to characterize the submicron-pore structures. Various types of porosities were observed on SEM images. Pores were found in organic matters with the size of nano level and occupied 40-50% of the kerogen body. The reconstructed 3D pore model provided key insights into the petrophysical properties of shale gas such as pore size histogram, porosity, tortuosity and anisotropy, etc. X-ray diffraction (XRD) analysis showed high illite content in Haynesville shale. It also suggested high calcite content in Utica shale samples. Wettability tests showed that most of the additives that were used can alter shale gas surfaces toward hydrophilic-like system (water-wet). Moreover, palynofacies analysis provided valuable information about kerogen type and its degree of thermal maturation, which are key parameters in shale gas exploration"--Abstract, p. iii.

The challenges in sustainable and efficient development of organic shales demand a better understanding of the micro-scale pore structure of organic shales. However, the characterization of shale pore structure is challenging because the pores can be very small in size (less than several nanometers). Besides, the pore network in shales can be very different from that of conventional reservoirs. A unique feature of the pore system in organic shales is that the formation of the pore network usually depends heavily on the maturation of organic matter. In this dissertation, the properties of the pore network in the shale matrix are investigated using pore-scale network modeling constrained by low pressure nitrogen sorption isotherms. In addition to the larger, induced fracture network generated during hydraulic fracturing, the flow pathways formed by microfractures and nanopores are important for economic hydrocarbon production formations. However, due to the difficulty in detecting and characterizing microfractures and the complexity of hydrocarbon transport in shales, the role of microfractures in hydrocarbon flow during production is still poorly understood. In this dissertation, the most up-to-date machine learning and deep learning tools are utilized to characterize microfractures propagation in organic rich shales. The microfracture lengths and fracture-mineral preferential association are studied. Later a microfracture is embedded in pore-scale network models to understand the role of microfracture in permeability enhancement of shale matrix. Shale samples from three different shale formations are studied in this dissertation. These formations are Barnett shale, Eagle Ford shale (Karnes County, TX), and a siliceous shale in the northern Rocky Mountains, USA (the specific location has been withheld at the donor’s request). By analyzing the nitrogen sorption isotherms for isolated organic matter clusters and the bulk shale samples, the pore size information in the organic matter and inorganic matter is explored for the Barnett shale samples. The network connectivity and pore spatial arrangement in the shale matrix is determined by comparing the modeled nitrogen sorption isotherms with laboratory experiment results. Later, the pore network model is used to predict the permeability of the shale matrix. Both Darcy permeability and apparent permeability (including Darcy flow and gas slip effect) are computed using the network model. The apparent permeability is much larger than the Darcy permeability from laboratory measurements and pore network modeling. Pore network models are constructed for four samples: two sample from Barnett shale, one from Eagle Ford and one from the siliceous samples. The pore network properties are characterized using nitrogen sorption isotherms. I concluded that on average, each pore is connected with two neighboring pores in shale matrix. The pore spatial arrangement is not totally random in the network. By analyzing the microfracture propagation in high resolution scanning electron microscopy (SEM) images for the Eagle Ford samples and siliceous samples, the fracture lengths and density in intact and deformed (in confined compressive strength testing) shale samples are explored. The preferential fracture-mineral association is scrutinized by analyzing the composed back-scatter electron (BSE) images and the energy dispersive x-ray spectroscopy (EDS) images for the Eagle Ford and Siliceous samples. The fractures and minerals are easily detectable after combining BSE and EDS images. The conclusion is that, the generation and closure of microfracture is closely related to total organic carbon (TOC), OM maturation, and minerology. A higher TOC indicate that more microfractures are generated during organic matter maturation. Clay dehydration is another reason for microfracture generation. However, the microfractures generated due to clay dehydration or organic matter maturation are also more sensitive the pressure dependent effect. Microfractures also develop at the grain boundaries of more brittle minerals such as quartz, calcite, and feldspar. The permeability of the pore network model containing one microfracture is computed for the Eagle Ford sample and the siliceous sample. The results suggest that the permeability of shale matrix increases greatly after one microfracture is added to the matrix. The relationship between permeability and fracture height-aperture ratio follows a logarithmic function for both samples. The relationship between permeability and lengths follows an exponential function for both samples. Fracture lengths have more impact on fracture permeability compared to height-aperture ratio

Advances in theories, methods and applications for shale resource use Shale is the dominant rock in the sedimentary record. It is also the subject of increased interest because of the growing contribution of shale oil and gas to energy supplies, as well as the potential use of shale formations for carbon dioxide sequestration and nuclear waste storage. Shale: Subsurface Science and Engineering brings together geoscience and engineering to present the latest models, methods and applications for understanding and exploiting shale formations. Volume highlights include: Review of current knowledge on shale geology Latest shale engineering methods such as horizontal drilling Reservoir management practices for optimized oil and gas field development Examples of economically and environmentally viable methods of hydrocarbon extraction from shale Discussion of issues relating to hydraulic fracking, carbon sequestration, and nuclear waste storage Book Review: I. D. Sasowsky, University of Akron, Ohio, September 2020 issue of CHOICE, CHOICE connect, A publication of the Association of College and Research Libraries, A division of the American Library Association, Connecticut, USA Shale has a long history of use as construction fill and a ceramic precursor. In recent years, its potential as a petroleum reservoir has generated renewed interest and intense scientific investigation. Such work has been significantly aided by the development of instrumentation capable of examining and imaging these very fine-grained materials. This timely multliauthor volume brings together 15 studies covering many facets of the related science. The book is presented in two sections: an overview and a second section emphasizing unconventional oil and gas. Topics covered include shale chemistry, metals content, rock mechanics, borehole stability, modeling, and fluid flow, to name only a few. The introductory chapter (24 pages) is useful and extensively referenced. The lead chapter to the second half of the book, "Characterization of Unconventional Resource Shales," provides a notably detailed analysis supporting a comprehensive production workflow. The book is richly illustrated in full color, featuring high-quality images, graphs, and charts. The extensive index provides depth of access to the volume. This work will be of special interest to a diverse group of investigators moving forward with understanding this fascinating group of rocks. Summing Up: Recommended. Upper-division undergraduates through faculty and professionals.

Unconventional reservoirs, specifically carbonates, tight gas sandstone and shale gas formations, provide significant potential for the growing world energy demand. However, the positive prospects of these reserves are hampered by considerable uncertainty in estimating their production. Reliable petrophysical models of these media can help reduce the uncertainty in their development. Pore-network models are cost-efficient representations of a porous medium's pore structure that allow prediction of its macroscopic properties. In this effort, the topology and fluid physics of pores from various scales are integrated into a single-entity three-dimensional (3D) unstructured pore-network model. We start with the simplest shale matrix gas flow model that incorporates pores from nanometer and micrometer scales, but has a connectivity resembling conventional rocks. We quantify the apparent permeability of these networks with relevant, pore size-dependent physical models applied to both scales and compare the results with the continuum no slip boundary condition assumption. The discrepancy between the two can run over several orders of magnitude and grows with the fraction of nanopores and the width of the overall pore size distribution. We next attempt to create more realistic network models, closer to the true topology of the studied unconventional rocks. Workflows for integration of nanometer and micrometer pore structures are then developed for deterministic, geologically informed, process-based and image-based approaches in various unconventional scenarios. We perform a systematic forward analysis of the applicability of tracer breakthrough profiles (TBPs) in revealing the pore structure of tight gas sandstone and carbonate formations. The following features are modeled via 3D multiscale networks: microporosity within dissolved grains and pore-filling clay, cementation in the absence and presence of microporosity (each classified into uniform, pore-preferred, and throat-preferred modes), layering, and vug and microcrack inclusion. A priori knowledge of the extent and location of each process is assumed known. In general, significant qualitative perturbation of the TBPs is observed for uniform and throat-preferred cementation. Layering parallel to the fluid flow direction has a considerable impact on TBPs whereas layering perpendicular to flow does not. Microcrack orientation has a minor effect in perturbing TBPs. In most scenarios TBPs show negligible qualitative sensitivity to the fraction of micropores present. The exception is the case when macropores and pore-filling micropores have equivalent flux contributions. A quantitative parameterization of sensitivity is not conducted; an example of such is measuring the perturbations in pore-volumes associated with the breakthrough profile peaks, has not been conducted. Similar to tracer breakthrough profiles in the context of characterizing heterogeneous porous media in core scale, nitrogen sorption hysteresis is investigated for characterizing pore structure of mudrocks. Three network types are introduced to represent their multiscale pore topology; specifically: regular (Type 1), series (Type 2) and parallel (Type 3). We conclude that, in appropriate size ranges, sorption hysteresis can distinguish the three types whereas permeability hysteresis can only separate parallel from series and regular. Furthermore, the simulations show that sorption hysteresis is sensitive to compaction/cementation (closing of throats) in all network types, whereas permeability hysteresis is sensitive to the diagenesis in parallel networks only. A quantitative parameterization of the sensitivity, such as measuring the area enclosed by the hysteresis curve, was not conducted. Molecular diffusion is an important mechanism for hydrocarbon transport within matrix as well as between matrix pores and hydraulic fractures in unconventional shale production. The diffusion coefficient is also an essential parameter in two-dimensional (2D) nuclear magnetic resonance (NMR) map interpretations. However, molecular diffusion in the micro- and nanometer scale pore networks of unconventional shale rocks remain poorly understood. We attempt to link the restricted diffusion coefficient to pore-scale characteristics of shale gas media. A random walk algorithm with discrete time steps is implemented to investigate the effects of pore-throat ratio (the ratio of pore-body radius to pore-throat radius), length ratio (the ratio of throat length to pore radius), pore shape and topology. It is concluded that, at an equal surface-to-volume ratio, diffusion coefficient increases in pores with higher angularity. The effects of pore-throat radius ratio and length ratio are explicitly modeled in 3D structured regular lattices. Results indicate that, up to pore-throat radius ratios of 5, restricted diffusion is considerable in lattices with zero length throats. Furthermore, restricted diffusion decreases with the increase in length ratio. To reduce computational costs, a statistical method is developed to render simulating the effects of connectivity and pore size distribution on 3D unstructured multiscale networks feasible. Finally, we perform a preliminary assessment of the fidelity of the multiscale process-based and image-based approaches in a case study conducted on the Wilcox tight gas sandstone. A novel workflow that combines the multiscale process-based network model with petrographic analysis is developed. This methodology utilizes petrographic information (grain size distribution and sorting, cement type and thickness, microporosity types and fractions, burial sequence) to enable the prediction of the flow properties of the medium in several burial stages throughout the paragenesis of the Wilcox formation. Given the 100 -1000 times scale difference between micropores and macropores and the resultant computational costs, an upscaling scheme is proposed for the microporous clusters in the process-based algorithm. The upscaling presently does not work for the image-based modeling because of the irregularity of microporous regions. We observe discrepancy between the simulated and experimental mercury injection capillary pressure curve and use it to recommend future improvements to the workflow. In this case study, micropores are crucial in contributing to the flow path; therefore, their surface chemistry as well as physical features such as surface roughness must be quantified and taken into account to make reliable predictions of the rock flow properties.

Advances in theories, methods and applications for shale resource use Shale is the dominant rock in the sedimentary record. It is also the subject of increased interest because of the growing contribution of shale oil and gas to energy supplies, as well as the potential use of shale formations for carbon dioxide sequestration and nuclear waste storage. Shale: Subsurface Science and Engineering brings together geoscience and engineering to present the latest models, methods and applications for understanding and exploiting shale formations. Volume highlights include: Review of current knowledge on shale geology Latest shale engineering methods such as horizontal drilling Reservoir management practices for optimized oil and gas field development Examples of economically and environmentally viable methods of hydrocarbon extraction from shale Discussion of issues relating to hydraulic fracking, carbon sequestration, and nuclear waste storage

With the successful development of shale oil and gas, there has been a great deal of concern about shale and its characteristics, especially in characterization technology, genesis, evolution and control factors of shale reservoirs. The pore structure of a shale reservoir is complex, and the nanometer pore is dominant, which can reach more than 80%. Since the size of oil and gas molecules is mainly below 100 nm, hydrocarbon molecules and petroleum asphaltenes can enter into the nano pores completely, but the capillary resistance in the nano pores restricts the free flow of fluid. There is a large viscous force and molecular force between the fluid in the nano pore throat and the surrounding media. The hydrocarbon molecules adhere to the surface of minerals and kerogen in the adsorption state and in the diffusion state. So, the nano pore network controls the occurrence and enrichment of shale oil and gas. The pore structure and porosity evaluation of shale mainly depends on mercury intrusion, gas adsorption, SEM, etc. The micro-nano pore 3D characterization technology, represented by focused ion beam scanning electron microscopy (FIB-SEM), has become the mainstream trend in shale nano pore analysis technology, which extends the observation scale of shale structure to the nano scale. With the development of shale reservoir description and characterization technology, the accuracy of characterize shale pores has been greatly improved, which provides a precondition for solving the formation, evolution, and oil-gas accumulation mechanism of unconventional reservoir pores.

This book details the analytical processes, and interpretation of the resulting data, needed in order to achieve a comprehensive source-rock evaluation of organic-rich shales. The authors employ case studies on Permian and Cretaceous shales from various Indian basins and other petroleum-bearing basins around the world to illustrate the key features of their organic-rich shale characterization methodology. These case studies may also help to identify potential zones within shale formations that could be exploited for commercial gas and/or oil production. Given its scope, the book will be of interest to all researchers working in the field of source-rock analysis. In addition, the source-rock evaluation techniques – and the various intricacies associated with them – discussed here offer valuable material for postgraduate geology courses.