Organic-rich shales in the last decade have become a focus of the oil and gas industry, and currently are the primary source of oil and gas production from Unconventional resources. These resources will be in need of a method of enhanced recovery to maximize lifetime production from each well. Spontaneous imbibition, or the adsorption of a fluid into a porous media due to capillary forces and consequent displacement of non-wetting fluids is a good potential enhanced recovery method. Measuring the amount of spontaneous imbibition in an organic-rich shale is complicated by several challenges compared to traditional oil reservoir rocks, such as the ultra-low permeability and the high clay content. This clay content can often lead to swelling, which can affect imbibition measurements. In this study, a new gravimetric method for measuring spontaneous imbibition is developed that can measure the rate, and volume of spontaneous imbibition as well as the degree of shale swelling. Two organic-rich shales, the Bakken and the Utica were examined and compared to establish the viability of the experimental method. The results of this work suggest that this method is a promising and viable method for measuring the volume and rate of spontaneous imbibition in organic-rich shale. The exposure of organic-rich shales to atmospheric conditions can significantly modify the properties of the shale through drying or hydration of the samples. All of the shales used in experiments in the following study were carefully maintained at their native state before exposure to the imbibition fluids. Additionally, the shale samples were exposed to several surfactant mixtures to measure the effect of these surfactants on the rate of imbibition.

The success of horizontal drilling and hydraulic fracturing has enabled the economic production of hydrocarbons from shale formations. However, wellbore instability and proppant embedment remain two major concerns during drilling and completion of wellbores in unconventional shale reservoirs. Both issues are largely controlled by shale-fluid interactions. Understanding the interactions of organic-rich shale with water-based fluids is the first step towards selecting appropriate drilling and fracturing fluids. The main objective of this study is to investigate the interactions of organic-rich shale with various water-based fluids. A series of measurements were performed to determine shale mineralogy, native water activity, fluid content, pore size distribution, Brinell hardness, Young's modulus, P-wave and S-wave velocities. It was shown that XRD and XRF yield consistent shale mineralogy, allowing us to make rapid determinations of shale mineralogy. Large variations in mineralogy were observed with shale samples from different formations. Even samples from the same well and at adjacent depths exhibited very different mineralogical makeup. The NMR T1/T2 ratio and T2 secular relaxation were used to distinguish pore fluids of different viscosity in pores of various sizes. A good correlation was established between the clay content and the amount of low-viscosity fluid in small pores, indicating that the water-saturated microporosity was in clay minerals. Combined N2GA and MICP measurements showed that a majority of the shale pores were found to be in the micropore to mesopore size range. Changes in shale mechanical properties were measured before and after shale samples came into contact with water-based fluids. The small degree of swelling and mechanical properties changes suggests that these organic-rich shales were only slightly sensitive to fluid exposure. Anisotropic swelling perpendicular and parallel to bedding planes could be due to the clay fabric anisotropy. The importance of using preserved shale samples was clearly demonstrated. Temperature and fluid pH were found to have significant impact on the reduction in shale mechanical stability after fluid exposure. Changes in both shale hardness and Young's modulus were observed with fluid exposure. Shales with higher clay content tend to experience greater reduction in modulus and hardness after contact with water-based fluids. A comparison between the measured fracture permeability damage and the calculated fracture permeability damage due to proppant embedment alone reveals that proppant embedment caused by shale softening is only partially responsible for the decrease in fracture permeability. Other mechanisms such as fines mobilization may be the dominant factors controlling fracture conductivity damage. Together these measurements allow us to rapidly screen drilling and fracturing fluids that are compatible with a particular shale by studying changes in shale mechanical properties before and after contact with water-based fluids. Potentially troublesome shales can be identified and possible solutions can also be evaluated using this measurement procedure.

The increasing significance of shale plays leads to the need for deeper understanding of shale behavior. Laboratory characterization of petrophysical properties is an important part of shale resource evaluation. The characterization, however, remains challenging due to the complicated nature of shale. This work aims at better characterization of shale using experiments, lab measurements, and machine leaning analysis. During hydraulic fracturing, besides tensile failure, the adjacent shale matrix is subjected to massive shear deformation. The interaction of shale pore system and shear deformation, and impacts on production remains unknown. This work investigates the response of shale nanoscale pore system to shear deformation using gas sorption and scanning electron microscope (SEM) imaging. Shale samples are deformed by confined compressive strength tests. After failure, fractures in nanoscale are observed to follow coarser grain boundaries and laminae of OM and matrix materials. Most samples display increases in pore structural parameters. Results suggest that the hydrocarbon mobility may be enhanced by the interaction of the OM laminae and the shear fracturing. Past studied show that the evolution of pore structure of shale is associated with thermal maturation. However, the evolution of shale transport propreties related to thermal maturation is unclear due to the difficulty of conducting permeability measurement for shale. This work studies evolution of permeability and pore structure measurements using heat treatment. Samples are heated from 110°C to 650°C. Gas sorption and GRI (Gas Research Institute) permeability measurements are performed. Results show that those petrophysical parameters, especially permeability, are sensitive to drying temperature. Multiscale pore network features of shale are also revealed in this study. Characterizing fluids in shale using nuclear magnetic resonance (NMR) T1-T2 maps is often done manually, which is difficult and subjected to human decisions. This work proposes a new approach based on Gaussian mixture model (GMM) clustering analysis. Six clustering algorithms are performed on T11-T2 maps. To select the optimal cluster number and best algorithm, two cluster validity indices are proposed. Results validate the two indices, and GMM is found to be the best algorithm. A general fluid partition pattern is obtained by GMM, which is less sensitive to rock lithology. In addition, the clustering performance can be enhanced by drying the sample

Confined Fluid Phase Behavior and CO2 Sequestration in Shale Reservoirs delivers the calculation components to understand pore structure and absorption capacity involving unconventional reservoirs. Packed with experimental procedures, step-by-step instructions, and published data, the reference explains measurements for capillary pressure models, absorption behavior in double nano-pore systems, and the modeling of interfacial tension in C02/CH4/brine systems. Rounding out with conclusions and additional literature, this reference gives petroleum engineers and researchers the knowledge to maximize productivity in shale reservoirs. Helps readers gain advanced understanding of methods of adsorption behavior in shale gas Presents theories and calculations for measuring and computing by providing step-by-step instructions, including flash calculation for phase equilibrium Includes advances in shale fluid behavior, along with well-structured experiments and flow charts

Provides comprehensive information about the key exploration, development and optimization concepts required for gas shale reservoirs Includes statistics about gas shale resources and countries that have shale gas potential Addresses the challenges that oil and gas industries may confront for gas shale reservoir exploration and development Introduces petrophysical analysis, rock physics, geomechanics and passive seismic methods for gas shale plays Details shale gas environmental issues and challenges, economic consideration for gas shale reservoirs Includes case studies of major producing gas shale formations