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The Woodford Shale formation is currently an important unconventional gas resource that extends across parts of the mid-continent of the United States. A resource shale acts as source, seal, and reservoir, and its characterization is vital to successful exploitation and production of hydrocarbons. This work is a surface seismic observation and investigation of the seismic anisotropy present in the Woodford Shale formation in the Anadarko Basin, Oklahoma. One of the main causes of anisotropy here is commonly believed to be vertical natural fractures (HTI) and horizontal alignment of clay minerals (VTI). Understanding the natural fracture orientation and density, as well as regional stress orientation, is important to the development of hydraulic fracturing programs in shales, such as the Woodford, producing natural gas. Dipole sonic log measurements in vertical boreholes suggest that the Woodford does possess vertical transverse isotropy (VTI), due possibly to horizontal layering or aligned clay minerals. Further, the borehole logs do not indicate horizontal transverse isotropy (HTI) associated with fracturing in the Woodford interval. An amplitude varying with angle and azimuth (AVAZ) analysis was applied to 3-D surface seismic data in the Anadarko Basin and shows the dipole sonic logs may not be completely characterizing the anisotropy observed in the Woodford. Once this apparent contradiction was discovered, additional work to characterize the fractures in the formation was undertaken. A petrophysical model based on the borehole data of the Woodford Shale was created, combining various techniques to simulate the rock properties and behavior. With a more complete rock physics model, a full stiffness tensor for the rock was obtained. From this model, synthetic seismic data were generated to compare to the field data. Furthermore, analytic equations were developed to relate crack density to AVAZ response. Currently, the application of this AVAZ method shows fracture orientation and relative variations in fracture density over the survey area. This work shows a direction for a quantified fracture density because the synthetic seismic data has a quantified fracture density at its basis. This allowed for a relationship to be established between explicit fracture parameters (such as fracture density) and AVAZ results and subsequently may be used to create regional descriptions of fracture and/or stress orientation and density.
The Woodford Shale in west-central Oklahoma is an organic and silica rich shale that is a prolific resource play producing gas and liquid hydrocarbons (Gupta et al., 2013). Unconventional shale wells are only producible due to modern hydraulic fracturing techniques. Production surveys from unconventional reservoirs show significant variability between wells and even between fracking stages (Kennedy, 2012). The production potential of a particular shale appears to be related to its brittleness and kerogen content "sweetness". Thus, brittleness analysis becomes important when choosing which shales to produce. A rocks brittleness index can be related directly to elastic properties derived from P- and S-wave velocities, as well as, its specific mineral makeup. This project's main focus is to determine the elastic rock properties that affect or relate to Woodford shale brittleness and how they relate to the rock's specific mineral makeup and kerogen content. Measurements to determine elastic properties, based on ultrasonic laboratory testing, were conducted on available Woodford cores. The estimated elastic moduli were evaluated via cross-plotting and correlation with a variety of rock properties. Elastic properties are of essential relevance to forward seismic modeling in order to study seismic response. Mineral makeup, determined via XRD and XRF analyses done by Kale Janssen (2017), was used to calculate a mineral-based brittleness index for comparison with the elastic moduli. Evaluation of the elastic moduli assisted in determining which elastic properties directly relate to the brittleness of the shales and, in turn, to geomechanical aspects. These properties were correlated with data from previous studies including mineral percentages, total organic content (TOC), and thermal maturity. These correlations were used to determine which elastic properties best predict a rock's brittleness index. The calculated brittleness was used to develop a brittleness index map of the Woodford Formation.
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Seismic anisotropy, defined as the dependency of seismic-wave velocities on propagation direction, is an important factor in seismic data analysis. Neglecting anisotropy can lead to significant errors in the subsurface images. Even after decades of considerable research efforts, the topic of anisotropy remains at the center of attention of the research community. In this dissertation, I address the fundamental problem of choosing parameterization to characterize the effects of seismic anisotropy and propose an alternative approach based on the Muir-Dellinger (MD) parameters. I first give their definitions and discuss their properties with respect to the classic qP-wave phase velocity in transversely isotropic (TI) media in the second chapter. I show that, when expressed in terms of MD parameters, the exact expression of phase velocity in this case is controlled by the elliptical background and two anelliptic parameters (q1 and q3) defined as the curvature of the qP-wave phase velocity measured along the symmetry axis and its orthogonal. The wide range of possible values for the vertical shear-wave velocity (vs0) expressed under the conventional Thomsen parameterization translates to a considerably narrower range of the slope in the nearly linear dependence between q1 and q3. This discovery suggests a possibility of using such a relationship to characterize the complete stiffness tensor, infer more information about the subsurface directly from qP kinematics, and provide a physical basis for reducing the number of parameters in qP-wave analysis. Based on various experimental measurements of stiffness coefficients reported in the literature, I relate such properties in shales, sandstones, and carbonates with corresponding values of slope. I further investigate this empirical linear relationship in the third chapter and show that it can also gives additional rock physics implications about the type of pore fluids. I provide some supportive evidence of its reality from self-consistent rock physics modeling and Backus averaging for shale samples. In addition, I find that both the 2D MD parameterization and its 3D extension, suitable for studies of qP waves in orthorhombic media, also provide a convenient foundation for the parameter estimation process. I carry out a detailed study on the sensitivity of MD parameters to qP-wave kinematics in comparison with other known anisotropic parameterization schemes in the fourth chapter. In the last chapter, using the MD parameters, I propose novel analytical approximations for qP-wave phase and group velocities in 2D TI and 3D orthorhombic media. The novel approximations are highly accurate and possess an advantage of having similar functional form with reciprocal coefficients, which adds practical convenience to considering both phase (wave) and group (ray) velocities. Finally, I discuss known limitations of the MD parameterization and suggest possible future research topics.