Shale gas production accounts for about 70% of the total natural gas production in the US. Yet it remains a nontrivial task to characterize the petrophysical properties of shale core samples either by experimental analysis or numerical simulations. Shale matrix has low porosity and permeability resulting from nanometer-scale pore sizes. Surface properties of shale can be quite inhomogeneous arising from complex mineralogy and diagenesis. Heterogeneous morphology and topology of the pore structure poses significant challenges on understanding fluid distribution and flow capacity. Pore scale simulations provide insight into the fundamental mechanisms of thermodynamics and hydrodynamics in tight porous materials, and can supplement experimental characterization of shale petrophysical properties (e.g. absolute/relative permeability, capillary pressure curves). However, challenges exist in creating representative pore structures tailored for specific simulation tools, incorporating the appropriate and relevant physics for the problems to be simulated, and interpreting, calibrating, or validating the simulation results. In this work, we used two types of pore scale simulation tools, namely pore network modeling (PNM) and lattice Boltzmann method (LBM), to study gas adsorption/desorption and transport behavior in shale matrix. For the first part of the work, a dual-scale PNM was integrated with lattice density functional theory (LDFT) to study nitrogen adsorption/desorption in mesoporous materials with pore sizes smaller than 200 nm. Critical pore structure parameters (i.e. porosity, pore size distribution, and pore throat connectivity) were characterized by calibrating the simulated nitrogen sorption isotherms to experimental results, and were then used to construct PNMs to study supercritical methane transport. We found that the pore structure characterization results were nonunique and highly dependent on the assumed pore shape. Scanning electron microscope (SEM) images were used to further constrain the description of pore shapes. Advection and diffusion of methane at reservoir conditions were simulated and compared, and suggestions were made regarding the choice of representative pore shape in PNMs for single phase advection/diffusion calculations. We next used LBM to study two-phase thermodynamic and hydrodynamic problems in nanopore systems in shale. Both 2D and 3D LBM models were developed with consideration of mesoscale fluid-fluid and solid-fluid interactions to model gas adsorption in complex geometries, and phase separation occurs automatically without the need to track the interface. This overcomes the pore shape deficiency of PNMs in cases where nanoporous media reconstruction exists. LBM models were then calibrated to LDFT and validated against experimental adsorption data for both subcritical and supercritical gases for the first time. We studied and compared nitrogen sorption hysteresis in two model nanopore system reconstructions representing the interparticle and intraparticle pores in shale. As another example of many possible applications of our developed model, we studied water adsorption and condensation in a reconstructed clay pore structure based on SEM image analysis, and explored the effect of surface wettability on adsorbed/condensed water distribution and connectivity. Supercritical methane flow simulations with the existence of condensed water were conducted using a 3D hydrodynamic LBM model that considers nanoscale flow physics for high Knudsen number flow. The relative permeability of methane as a function of water saturation and surface wettability was calculated and compared to available experimental data measured on geosynthetic clay liners. We demonstrated the wide applicability of our model and suggested future applications

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

Shale gas and liquid-rich shales have become important energy sources in the US and other parts of the world. Unlike conventional oil and gas reservoirs, unconventional shale resources contain a very heterogeneous pore system. The pore size varies between micro-, meso- and macroscales (2 nm, 2-50 nm and 50 nm). The mineral composition of shale rocks varies widely as well from clay-rich to calcite-rich. The nanoscale nature of the pores, coupled with rock mineral heterogeneity, makes the "conventional'' understanding of fluid transport in conventional reservoirs no longer suitable to explain and predict accurately the flow behavior in unconventional resources. The research work aimed to bridge the gap in the understanding of the fluid flow behavior of unconventional resources by applying various experimental and molecular simulation tools. Specifically, this research work studied how the rock (i.e. permeability), the fluid (i.e. composition and phase behavior) and the fluid-rock interactions (i.e. adsorption) all behaved with depletion in nanoporous rock formations. Several laboratory experiments and molecular simulation techniques were applied in this research work. Laboratory experiments included a gas-condensate core-flooding experiment, permeability measurements and adsorption measurements. In the core-flooding experiment, a real gas-condensate mixture obtained from the Marcellus shale play was injected into a Marcellus shale core at in-situ conditions and the composition of gas samples collected along the core was monitored during flow. To investigate the effect of rock mineralogy and pore structure on the transport mechanisms in nanoporous shale reservoirs, the permeability of Utica, Permian and Eagle Ford shale samples were measured using argon as a nonadsorbing gas and CO2 as an adsorbing gas. In addition, CO2 adsorption experiments were conducted on different shale samples in order to investigate the role of shale mineral constituents in adsorption. Moreover, molecular simulation techniques were applied to model the selective adsorption of binary hydrocarbon mixtures in carbon-based slit-pores and to estimate the shift in the critical properties of hydrocarbons due to confinement in nanometer-size pores. The molecular simulation techniques included the grand canonical Monte Carlo (GCMC) and the Gibbs ensemble Monte Carlo (GEMC). This research work revealed that clay content in shale reservoirs played a significant role in the stress-dependent permeability. For clay-rich samples, higher pore throat compressibility was observed which in turn led to higher permeability reduction with increasing effective stress compared to calcite-rich samples. Numerical simulation results showed that failing to account for stress-dependent permeability in clay-rich shale reservoirs may lead to overestimating the cumulative gas recovery by a factor of two after ten years of production. Permeability measurements with CO2 indicated that CO2 permeability decreased in comparison with the nonadsorbing gases by as high as an order of magnitude due to a combination of CO2 adsorption, sorption-induced swelling and molecular sieving effects. CO2 adsorption measurements indicated that adsorption was controlled mainly by the clay content. Clay-rich shale samples showed higher adsorption capacity compared to clay-poor shale samples. The predominant clay mineral in those shale samples was illite. The platy shape of illite provided the surface area for enhanced adsorption capacity. This study concluded that in gas-condensate systems of liquid-rich shales, the produced gas becomes leaner during production and significant volumes of condensates, which contain predominantly heavy components, are left behind in the reservoir. The gas-condensate core-flooding experiment showed that composition of the flowing mixture below the dew-point pressure contained less heavy components along the direction of flow. Molecular simulations revealed that the change in gas composition was not only due to condensate dropout and relative permeability effects, but also due to the preferential adsorption of heavy hydrocarbons over methane. This means that initial production from shale reservoirs contain both methane and other heavy components from the free phase. However, as reservoir pressure decreases, methane from the adsorbed phase starts to desorb preferentially and the adsorption sites where methane molecules used to reside start to accept heavier components. In addition, molecular simulations conducted at subcritical conditions to estimate the vapor and liquid densities of pure hydrocarbons inside 5 and 10-nm pores revealed that rock-fluid interactions in the form of adsorption caused the critical pressure and temperature of the confined molecules to decrease. This was observed clearly for methane and ethane. The decrease in the critical properties was affected by the size of the pores. For example, the estimated critical pressure and temperature of methane in 5-nm pore were lower than the critical pressure and temperature in 10-nm pore.

Here is a basic introduction to Lattice Boltzmann models that emphasizes intuition and simplistic conceptualization of processes, while avoiding the complex mathematics that underlies LB models. The model is viewed from a particle perspective where collisions, streaming, and particle-particle/particle-surface interactions constitute the entire conceptual framework. Beginners and those whose interest is in model application over detailed mathematics will find this a powerful 'quick start' guide. Example simulations, exercises, and computer codes are included.

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.

Petrophysical Characterization and Fluids Transport in Unconventional Reservoirs presents a comprehensive look at these new methods and technologies for the petrophysical characterization of unconventional reservoirs, including recent theoretical advances and modeling on fluids transport in unconventional reservoirs. The book is a valuable tool for geoscientists and engineers working in academia and industry. Many novel technologies and approaches, including petrophysics, multi-scale modelling, rock reconstruction and upscaling approaches are discussed, along with the challenge of the development of unconventional reservoirs and the mechanism of multi-phase/multi-scale flow and transport in these structures. Includes both practical and theoretical research for the characterization of unconventional reservoirs Covers the basic approaches and mechanisms for enhanced recovery techniques in unconventional reservoirs Presents the latest research in the fluid transport processes in unconventional reservoirs