The oil and gas industry makes up approximately 1% of Texas’s overall water use (TWDB, 2012), but assessing water use on a regional and county level could show that the impacts from the oil and gas industry can be greater on a local level. Water planners within in Texas are becoming more concerned with how regional and local impacts from upstream development of oil and gas. These areas are under water-stressed conditions due to drought. To better understand potential local use impacts this study conducted qualitative and quantitative analyses. The qualitative analysis gathered input from stakeholders including representatives in the oil and gas industry, regulatory sector, and Texas water planning entities. This study utilized two public databases called FracFocus to assess average water use trends over time for the Eagle Ford region in south Texas and the Spraberry/Wolfcamp formations in west Texas. According to the qualitative analysis conducted trends toward increasing use of brackish groundwater and some recycling and reuse techniques by some operators are occurring in both regions. Also, there were slightly increasing trends of average water use per a well over time for both regions between January 2011 and April 2013. This analysis can be misrepresentative of the cause of the change in water use by the oil and gas industry, and therefore requires more data. The FracFocus database lacks the direction of the well, the lateral length of the well, and the mass of the proppant. These inputs would allow for a holistic analysis by water planners. vii The oil and gas industry can have local impacts on water use in particular regions. An increasing importance for regional water planners to have access to accurate oil and gas water use data is apparent. Collaboration between the oil and gas industry and Texas regional water planners will be a key component in areas with heavier mining water demands. Conclusively, the need for a more robust data set for regulators, industry professionals, and other stakeholders to access will benefit the strategic assessments oil and gas water use on local levels. / text

This dissertation focuses on interpreting the spatial variations of seismic amplitude data as a function of rock properties for the Haynesville Shale. To achieve this goal, I investigate the relationships between the rock properties and elastic properties, and calibrate rock-physics models by constraining both P- and S-wave velocities from well log data. I build a workflow to estimate the rock properties along with uncertainties from the P- and S-wave information. I correlate the estimated rock properties with the seismic amplitude data quantitatively. The rock properties, such as porosity, pore shape and composition, provide very useful information in determining locations with relatively high porosities and large fractions of brittle components favorable for hydraulic fracturing. Here the brittle components will have the fractures remain opened for longer time than the other components. Porosity helps to determine gas capacity and the estimated ultimate recovery (EUR); composition contributes to understand the brittle/ductile strength of shales, and pore shape provides additional information to determine the brittle/ductile strength of the shale. I use effective medium models to constrain P- and S-wave information. The rock-physics model includes an isotropic and an anisotropic effective medium model. The isotropic effective medium model provides a porous rock matrix with multiple mineral phases and pores with different aspect ratios. The anisotropic effective medium model provides frequency- and pore-pressure-dependent anisotropy. I estimate the rock properties with uncertainties using grid searching, conditioned by the calibrated rock-physics models. At well locations, I use the sonic log as input in the rock-physics models. At areas away from the well locations, I use the prestack seismic inverted P- and S-impedances as input in the rock-physics models. The estimated rock properties are correlated with the seismic amplitude data and help to interpret the spatial variations observed from seismic data. I check the accuracy of the estimated rock properties by comparing the elastic properties from seismic inversion and the ones derived from estimated rock properties. Furthermore, I link the estimated rock properties to the microstructure images and interpret the modeling results using observations from microstructure images. The characterization contributes to understand what causes the seismic amplitude variations for the Haynesville Shale. The same seismic reservoir characterization procedure could be applied to other unconventional gas shales. / text

Many of the current analytical techniques originally developed to characterize conventional reservoir rocks and fluid cannot adequately measure shale and source rocks. An example of this is Retort, where it is not feasible to get sufficient fluid from source rock to make useful measurements. The primary interest of this thesis is the exploration of other analytical techniques, two of which are previously unused in the oil and gas industry. These are Thermal Gravimetric Analysis (TGA), Pyrolysis-Gas Chromatography-Mass Spectrometry (Py-GC-MS), and Nuclear Magnetic Resonance (NMR). The techniques proposed offer valuable insight into the properties of the rock. TGA gives accurate weight of a sample as temperature is increased, Py-GC-MS is useful for identifying exact molecules in vaporized fluid, and NMR can be used to characterize viscosity and hydrocarbon chain length. The methods using these techniques can be utilized to further confirm mineralogy of a sample, identify the fluid constituents and quantify their weight, analyze changes in a sample between two different states, and calculate the free fluid saturations of oil and gas in shales. Procedures and results for each of these are presented in this thesis to show methodology and give the reader an idea of its useful applications. / text

The incompatibility of cement and shale and the subsequent failure of primary cementing jobs is a very significant concern in the oil & gas industry. On wells ranging from hydraulically fractured shale land wells to deepwater wells, this incompatibility leads to an increased risk in failing to isolate zones, which could possibly present a well control hazard and can lead to sustained casing pressure. The cement-shale interface presents a weak link that often becomes compromised by the loads incurred either during drilling, completion/stimulation or production phases. To formulate cements for effective zonal isolation, it is crucial to evaluate the bond strength of the cement-shale interface. Although several studies have focused on the interactions between cement and sandstone, very few studies have addressed the bonding behavior of cement with shale. The conventional push-out test protocol used to measure cement-to-sandstone shear bond strength has proven to be difficult to apply on shale due to its laminated or brittle nature that complicates sample preparation and can lead to shale or cement matrix failure instead of failure at the interface. In this paper, we present a novel, simple and versatile laboratory test procedure to measure the shear bond strength between cement and shale. The new procedure was used to develop cement formulations to improve the cement-to-shale bond. Two different design approaches were investigated. One involves introducing Gilsonite into cement to maintain shale integrity. The second design involves using surfactant to improve cement interfacial sealing property. Our results indicate that bond strength of cement with shale can be enhanced significantly incorporating surfactant in cement slurries. / text

This study examines the regional stratigraphic architecture, depositional systems, and petrographic characteristics of the South Texas Pearsall shale-gas system currently developed in the Indio Tanks (Pearsall) and Pena Creek (Pearsall) fields. The Pearsall Formation was deposited as a mixed carbonate-siliciclastic system on a distally steepened ramp over a period of 11.75 million years. It was deposited between maximum floods of two second-order sequences and contains at least five third-order cycles. Up to three Oceanic Anoxic Events (OAE 1-A, Late Aptian Regional Event, and OAE 1-B) figure prominently in the deposition of the Pearsall sediments, and during these intervals, depending on the location within the Maverick Basin, sedimentation rates were between 0.5 and 2 cm/ky. Facies in the Pearsall section arise from interactions between pre-existing topography, oxygenation regime, eustatic sea-level fluctuation, and depositional processes. In the Pearsall Formation, OAEs affected depositional environments and resulting facies patterns during several time periods. The OAEs occurred in association with transgressions but not necessarily in concert with them. Outer ramp OAE facies are siliciclastic-dominated, TOC-rich, and little-bioturbated. Conversely the outer ramp facies deposited under normally oxygenated paleoenvironmental conditions tend to be carbonate-rich, TOC-poor, and are more prominently bioturbated. / text

In today’s energy sector, it has been observed a revolutionary increase in shale gas recovery induced by reservoir fracking. So-called unconventional reservoirs became profitable after introducing a well stimulation technique. Some of the analysts expect that shale gas is going to expand worldwide energy supply. However, there is still a lack of an efficient as well as accurate modeling techniques, which can provide a good recovery and production estimates. Gas transports in shale reservoir is a complex process, consisting of slippage effect, gas diffusion along the wall, viscous flow due to the pressure gradient. Conventional industrial simulators are unable to model the flow as the flow doesn’t follow Darcy’s formulation. It is significant to build a unified model considering all given mechanisms for shale reservoir production study and analyze the importance of each mechanism in varied conditions. In this work, a unified mathematical model is proposed for shale gas reservoirs. The proposed model was build based on the dual porosity continuum media model; mass conservation equations for both matrix and fracture systems were build using the dusty gas model. In the matrix, gas desorption, Knudsen diffusion and viscous flow were taken into account. The model was also developed by implementing thermodynamic calculations to correct for the gas compressibility, or to obtain accurate treatment of the multicomponent gas. Previously, the model was built on the idealization of the gas, considering every molecule identical without any interaction. Moreover, the compositional variety of shale gas requires to consider impurities in the gas due to very high variety. Peng-Robinson equation of state was used to com- pute and correct for the gas density to pressure relation by solving the cubic equation to improve the model. The results show that considering the compressibility of the gas will noticeably increase gas production under given reservoir conditions and slow down the production decline curve. Therefore, for a more accurate prediction of shale gas production, it is crucial to consider compressibility behavior of the gas.

Within fractured reservoirs, such as tight gas reservoir, coupled processes between matrix deformation and fluid flow are very important for predicting reservoir behavior, pore pressure evolution and fracture closure. To study the coupling between gas desorption and rock matrix/fracture deformation, a poroelastic constitutive relation is developed and used for deformation of gas shale. Local continuity equation of dry gas model is developed by considering the mass conservation of gas, including both free and absorbed phases. The absorbed gas content and the sorption-induced volumetric strain are described through a Langmiur-type equation. A general porosity model that differs from other empirical correlations in the literature is developed and utilized in a finite element model to coupled gas diffusion and rock mass deformation. The dual permeability method (DPM) is implemented into the Finite Element Model (FEM) to investigate fracture deformation and closure and its impact on gas flow in naturally fractured reservoir. Within the framework of DPM, the fractured reservoir is treated as dual continuum. Two independent but overlapping meshes (or elements) are used to represent these kinds of reservoirs: one is the matrix elements used for deformation and fluid flow within matrix domain; while the other is the fracture element simulating the fluid flow only through the fractures. Both matrix and fractures are assumed to be permeable and can accomodate fluid transported. A quasi steady-state function is used to quantify the flow that is transferred between rock mass and fractures. By implementing the idea of equivalent fracture permeability and shape-factor within the transfer function into DPM, the fracture geometry and orientation are numerically considered and the complexity of the problem is well reduced. Both the normal deformation and shear dilation of fractures are considered and the stress-dependent fracture aperture can be updated in time. Further, a non-linear numerical model is constructed by implementing a poroviscoelastic model into the dual permeability (DPM)-finite element model (FEM) to investigate the coupled time-dependent viscoelastic deformation, fracture network evolution and compressible fluid flow in gas shale reservoir. The viscoelastic effect is addressed in both deviatoric and symmetric effective stresses to emphasize the effect of shear strain localization on fracture shear dilation. The new mechanical model is first verified with an analytical solution in a simple wellbore creep problem and then compared with the poroelastic solution in both wellbore and field cases.

Thesis (M.S.)--West Virginia University, 2009. / Title from document title page. Document formatted into pages; contains ix, 100 p. : ill. (some col.), col. maps. Includes abstract. Includes bibliographical references (p. 72-73).

Thesis (doctoral)--University of Tartu, 1998. / Includes bibliographical references.

Thesis (M.S.)--University of Missouri-Columbia, 2004. / Typescript. Includes bibliographical references (leaves 22-25). Also available on the Internet.