Pore structures within two Barnett shale samples at the microscale and macroscale were constructed based on conventional core analysis techniques (mercury intrusion capillary pressure (MICP), nitrogen sorption, and helium porosimetry). Measurements were performed on both bulk samples (core 2 and core 6) and organic matter isolated from bulk samples. Pore size distributions obtained from both core 2 and core 6 contain a large volume of micropores, while pore size distributions obtained from isolated organic matter do not, indicating that organic matter-associated pores are mesopores and most of the micropores are within the matrix. The organic matter-associated pore volume of core 2 is about 22% of the total pore volume, and the organic matter-associated pore volume of core 6 is about 41% of the total pore volume. A bundle of short conduits model with constraints can explain the measured nitrogen desorption isotherm on organic matter, and this model was used to represent the microscale pore structure within organic matter. Fragment size effect was observed on both MICP curves and nitrogen sorption isotherms measured on bulk Barnett samples: smaller fragment size results in larger mercury intrusion or nitrogen gas sorption. Fragment size effect does not appear in helium porosity measurement on bulk samples.

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.

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

Unconventional gas and oil reservoirs, also known as Shale reservoirs, represent a significant source of hydrocarbons, particularly in the US. The development of the industry has been the focus of research efforts over the last decade. However, the estimated ultimate recovery for these unconventional resources remains below 25% for gas and 5% for oil resources. Factors such as the limited understanding of processes occurring in the reservoir, the gaps in the analysis of matrix properties, and the scarcity of methods for the study of properties alteration, are responsible for the reduced ultimate recovery. In the work herein presented, I describe the synergistic use of multicomponent gas adsorption and Time-Domain Nuclear Magnetic Resonance (TD-NMR), along with complementary techniques, to effectively study shale porous media. The Characterization methods are used to gain valuable information regarding the evolution or changes of the porous media under different reactive environments, considering scenarios that include the interaction with stimulation fluid, fluids of different pH, among others. The evidence obtained shows that the combination of Gas Adsorption along with NMR is able to provide an acceptable description of the pore structure at different scales (micro, meso, and macro-pore regions), and allows one to infer the nature of rock changes on the surface properties (wettability) or the structure of the matrix. Furthermore, results evidenced the importance of understanding the behavior of all the reservoir components, e.g. organic matter or native formation water, to develop an accurate understanding of the alteration process a shale rock undergoes.

This book summarizes the authors' extensive experience and interdisciplinary approach to demonstrate how acquiring and integrating data using a variety of analytical equipment can provide better insights into unconventional shale reservoir rocks and their constituent components. It focuses on a wide range of properties of unconventional shale reservoirs, discussing the use of conventional and new analytical methods for detailed measurements of mechanical properties of both organic and inorganic constituent elements as well as of the geochemical characteristics of organic components and their origins. It also addresses the investigation of porosity, pore size and type from several perspectives to help us to define unconventional shale formation. All of these analyses are treated individually, but brought together to present the rock sample on a macro scale. This book is of interest to researchers and graduate students from various disciplines, such as petroleum, civil, and mechanical engineering, as well as from geoscience, geology, geochemistry and geophysics. The methods and approaches can be further extended to biology and medicine.

"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.