Browsing by Subject "Kerogen"
Now showing 1 - 3 of 3
Results Per Page
Sort Options
Item Mineral, fluid, and elastic property quantification from well logs and core data in the Eagle Ford shale play : a comparative study(2013-08) Kwabi, Essi; Torres-Verdín, CarlosOrganic shales have become one of the greatest sources of hydrocarbon thanks to novel production techniques such as hydraulic fracturing. A successful hydraulic fracturing job, however, is dependent on several rock properties such as mineralogy and elasticity. A reliable estimation of such properties is therefore necessary to determine ideal rocks for horizontal well placement. In this study, rock types within the Eagle Ford shale that would be suitable for hydraulic fracturing are identified through interpretations of available well logs and core data. A comparative study of petrophysical properties such as mineral content, kerogen type and maturity, porosity, and saturation in six wells is performed to characterize the Eagle Ford shale. Two of the wells studied are within the wet gas window of the shale while the remaining four are in the oil window. Based on the calculated petrophysical properties, rock typing was performed using k-means clustering. Two rock types (RT1 and RT2) were identified and their compositions compared in each well. Elastic properties for the various rock types identified were then estimated using the differential effective medium (DEM) theory and were validated through simulation of slowness logs. The final rock type assessment was then performed to identify ideal rocks for hydrofracturing. Results indicate that the Eagle Ford mineralogy varies greatly with depth and with geographic location relative to the San Marcos Arch, a geological arching prominence across the shale. Northeast of the arch, the Eagle Ford shale is clay-rich. Preferred rocks for hydrocarbon production, RT1, are characterized by volumetric concentrations of ~0.44 carbonate, ~0.09 kerogen, ~0.07 porosity, and ~0.42 clay; RT1 also exhibits high sonic velocities (> 3400 m/s and > 1500 m/s compressional and shear, respectively) and high apparent electrical resistivity (> 2 ohm-m). In the Southwest region, on the other hand, the Eagle Ford shale is mostly calcareous. Ideal rocks in the region, RT1, are rich in kerogen (~0.1) with carbonate content of ~0.56, ~0.1 porosity, ~0.19 clay content, and resistivity > 20 ohm-m. In both regions, porosity and pore aspect ratio displayed substantial effects on elastic properties. For example, over 80% decrease in Young’s modulus was quantified when pore aspect ratio approached zero; high pore aspect ratio is preferred for stiff rocks. Poisson’s ratio estimates were not always reliable therefore fracturability was assessed based on Young’s modulus estimates. The study shows that depth intervals exhibiting Young’s moduli above 18GPa and 21GPa in the Northeast and Southwest region, respectively, are suitable for hydrofracturing.Item Nature of clay-kerogen associations in the oil shales from the Washakie Basin of the Green River formation (Wyoming).(Texas Tech University, 1975-05) Lee, Roger WilliamNot availableItem Seismic sensitivity to variations of rock properties in the productive zone of the Marcellus Shale, WV(2013-12) Morshed, Sharif Munjur; Tatham, R. H. (Robert H.), 1943-The Marcellus Shale is an important resource play prevalent in several states in the eastern United States. The productive zone of the Marcellus Shale has variations in rock properties such as clay content, kerogen content and pore aspect ratio, and these variations may strongly effect elastic anisotropy. The objective of this study is to characterize surface seismic sensitivity for variations in anisotropic parameters relating to kerogen content and aspect ratio of kerogen saturated pores. The recognized sensitivity may aid to characterize these reservoir from surface seismic observations for exploration and production of hydrocarbon. In this study, I performed VTI anisotropic modeling based on geophysical wireline log data from Harrison County, WV. The wireline log data includes spectral gamma, density, resistivity, neutron porosity, monopole and dipole sonic logs. Borehole log data were analyzed to characterize the Marcellus Shale interval, and quantify petrophysical properties such as clay content, kerogen content and porosity. A rock physics model was employed to build link between petrophysical properties and elastic constants. The rock physics model utilized differential effective medium (DEM) theory, bounds and mixing laws and fluid substitution equations in a model scheme to compute elastic constants for known variations in matrix composition, kerogen content and pore shape distribution. The seismic simulations were conducted applying a vertical impulse source and three component receivers. The anisotropic effect to angular amplitude variations for PP, PS and SS reflections were found to be dominantly controlled by the Thomsen Ɛ parameter, characterizing seismic velocity variations with propagation direction. These anisotropic effect to PP data can be seen at large offset (>15o incidence angle). The most sensitive portion of PS reflections was observed at mid offset (15o-30o). I also analyzed seismic sensitivity for variations in kerogen content and aspect ratio of structural kerogen. Elastic constants were computed for 5%, 10%, 20% and 30% kerogen content from rock physics model and provided to the seismic model. For both kerogen content and aspect ratio model, PP amplitudes varies significantly at zero to near offset while PS amplitude varied at mid offsets (12 to 30 degree angle of incidences).