Foams have been used successfully in the industry for both drilling and fracturing. These foams usually consist of both an aqueous liquid phase and a gas phase; air, nitrogen, and/or CO2 are the most common. Due to the aqueous liquid component in the foam, drilling and fracturing in shale formations can cause swelling and collapsing of the rock through formation invasion. Sensoy et al.(2009) has shown that the addition of nanoparticle dispersions to water based fluids reduces the amount of water invading the shale and has been used as a kickoff point for this research. Results presented in this thesis show that the addition of nanoparticles to foams enhances the performance of these fluids by reducing their invasion into shale. The use of foams allows for a low concentration of nanoparticles making this technology much more economically feasible for field testing and use. / text

A proper understanding of reservoir connectivity is essential to understanding the relationship between the porosity and the permeability within it. Additionally, the construction of an accurate reservoir model cannot be accomplished without this information. While a great deal is known about the connectivity in conventional sandstone systems, little is understood about the connectivity and its resultant properties within shale systems. Percolation theory is a method to describe the global properties of the shale system by understanding the nanometer scale interaction of pore space. In this study we use both analytical and empirical techniques to further understand shale pore scale interactions as well as global phenomena of the shale system. Construction of pore scale connectivity simulations on lattice and in the continuum allow for understanding relationships between pore topology, system porosity and system permeability. Additionally, questions regarding the role of Total Organic Carbon as well as natural fractures in contributing to shale permeability will be discussed. Analytical techniques are used to validate simulation results regarding the onset of percolation and related pore topology. Finally, time of flight simulation is used to further understand pressure transient behavior in the resulting topological models. High aspect ratio pores are shown to be the driver of shale permeability as opposed to the low aspect ratio pore space associated with organic matrix. Additionally, systems below the percolation threshold are likely able to produce because the wellbore will often encounter near infinite clusters. Finally, a characteristic volume growth profile is shown for a multi-porosity system whereby each level of porosity displays a corresponding stair step of volume growth in time.

Thesis (M.S.)--Auburn University, 2007. / Abstract. Vita. Includes bibliographic references (ℓ. 106-117)

Thesis (Chem. E)--New York University, (1917). / At head of title: State of Michigan. Department of Conservation. Geological Survey Division. In cooperation with the Department of Chemical Engineering, University of Michigan. Includes bibliographical references.

Thesis (M.S.)--University of Wisconsin--Madison, 1983. / Typescript. eContent provider-neutral record in process. Description based on print version record. Includes bibliographical references (leaves 103-115).

Thesis (Ph. D.)--University of Texas at Austin, 2005. / Supervisors: Martin E. Chenevert and Mukul M. Sharma. Vita. Includes bibliographical references.

Thesis (M.S.)--University of Wisconsin--Madison, 1982. / Typescript. eContent provider-neutral record in process. Description based on print version record. Includes bibliographical references (leaves 96-99).

Thesis (Ph. D.)--University of Texas at Austin, 2005. / Supervisors: Martin E. Chenevert and Mukul M. Sharma. Vita. Includes bibliographical references.

The McCully gas field is located approximately 10 km from the town of Sussex in southern New Brunswick, Canada. There are currently 32 active natural gas production wells which produce dry gas and condensates from the low-permeability Hiram Brook sandstone and Frederick Brook shale members of the Carboniferous Albert formation. The wells range from inclined to vertical, and have been hydraulically fractured in order to stimulate production. This study provides new geochemical data that allows for characterization of deep fluids in the McCully field and the porewaters in four shallow cores from fractured sandstone and siltstone units drilled adjacent to gas wells. Deep formation fluids of the Hiram Brook and Frederick Brook reservoirs were characterized by sampling production gas and produced water from the wellheads of production wells. Chemical and stable isotope compositions of the gas samples were determined by gas chromatography (GC) and gas-chromatography isotope-ratio-mass-spectroscopy (GC-IRMS), and compositions of the water samples were determined by inductively-coupled-plasma mass spectroscopy (ICP-MS), optical-emission spectroscopy (ICP-OES), and isotope-ratio mass spectroscopy (IRMS). Results indicate that gas compositions differ significantly between the two reservoirs, with the deeper Frederick Brook displaying greater maturity and evidence of isotope reversal. Results from the production water samples indicate that the salinity of formation water is as high as 53,600 mg/kgw (milligrams per kilogram water), and that salinity of the formation water was likely derived from a marine source. However, the strength of conclusions about the formation water composition is limited because the produced water was affected by refluxing in the wellhead, and by the formation of precipitates after sampling. Porewater from low-permeability drill-core samples was extracted using the ‘paper-absorption’ method. Vertical composition profiles were prepared for four observation wells, and the data indicate that porewater composition in these rocks is strongly controlled by lithology, redox conditions, and proximity to fractures that act as conduits for meteoric water.

Master of Science / Department of Geology / Matthew W. Totten / The Woodford Shale has received significant research interest as the number of productive wells has increased. The Woodford is productive over a wide range of thermal maturity (based upon vitrinite reflectance), yet most clay mineral studies report primarily illite (Caldwell, 2011 & Whittington, 2009). A previous report contrasts this behavior to other late Paleozoic shales in Oklahoma (Kowal, 2016). The major difference between these units is the amount of organic matter, which is much higher in most Woodford samples. In this study, Woodford shale samples were analyzed for several different characteristics, and combined with organic fraction data from previous work on the same samples (Lambert, 1993). Clay mineralogy was determined using an X-ray diffractometer (XRD) with the goal of finding the amount, and the degree of crystallinity of illite in a suite of samples. X-ray fluorescence (XRF) analysis was conducted to determine the variability of elemental concentrations within the samples. The bulk powder XRD data were combined with the major element concentrations to calculate mineral percentages. These data were compared to thermal maturity based upon vitrinite reflectance and Tmax values to determine the role of burial diagenesis on the clay mineralogy within Woodford Shale. The predominant clay mineral found within the samples was illite, with no recognizable mixed-layer smectite present, suggesting illitization is occurring early in the diagenetic process. A positive correlation between K/Rb ratios and TOC was found, supporting the control of organic matter on potassium in shales. No correlation between amount illite and thermal maturity was found, providing more evidence for the theory that high amounts of organics are driving illitization rather than thermal maturity.