Browsing by Subject "Fracture characterization"
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Item Anisotropic analysis and fracture characterization of the Haynesville Shale, Panola County, Texas(2015-08) Barone, Anthony William; Sen, Mrinal K.; Spikes, Kyle T; Grand, Stephen PIn unconventional resources such as the Haynesville Shale, a proper understanding of natural fracture patterns is essential to enhancing the economic success of petroleum extraction. The spatial density of naturally occurring fracture sets affects drainage area and optimal drilling location(s), and the azimuth of the strike of the predominant fracture set affects the ideal orientation of wells. In the absence of data to directly determine these fracture characteristics, such as Formation Microimaging (FMI) logs, these natural fracture patterns can be analyzed by examining the seismic anisotropy present in the reservoir. Anisotropy introduced from aligned fracture sets creates predictable azimuthal variations in the seismic wavefield. This allows the reservoir anisotropy, and thus the fracturing present in the reservoir, to be studied indirectly through the azimuthal analysis of industry standard 3D seismic data. The work presented here outlines three distinct methodologies, which utilize azimuthal amplitude variations (AVAZ) present in 3D seismic data, to infer fracture characteristics without the need for substantial well log information. Two of these methods have been previously established and assume the reservoir to be characteristic of Horizontally Transverse Isotropic (HTI). The last method is novel and assumes orthorhombic anisotropy when inverting for fracture density and is able to unambiguously invert for fracture azimuth. All methodologies used in this work produced similar results, increasing confidence in the accuracy of these results through statistical repeatability. Fracture density inversion results indicate spatially varying fracture density throughout the area, with a distinct area of higher fracture density present in the Northwestern corner of the area analyzed. Spatially varying fracture density and localized pockets of fracturing is consistent with expectation from analyzing production data and FMI logs from other areas of the Haynesville. Fracture azimuth inversion results showed some variability; however, the novel method presented in this thesis indicates that the azimuth of the predominant fracture set is oriented at a compass bearing of approximately 82 degrees – rotated slightly counterclockwise from an east-west orientation. Fracture azimuth results agree well with expectations from a regional stress analysis and from examining comparable formations with known fracture patterns in the surrounding area.Item Fracture characterization of a carbonate reservoir in the Arabian Peninsula(2013-05) Alhussain, Mohammed Abdullah; Sen, Mrinal K.Estimation of reservoir fracture parameters, fracture orientation and density, from seismic data is often difficult because of one important question: Is observed anisotropy caused by the reservoir interval or by the effect of the lithologic unit or multiple units above the reservoir? Often hydrocarbon reservoirs represent a small portion of the seismic section, and reservoir anisotropic parameter inversion can be easily obscured by the presence of an anisotropic overburden. In this study, I show examples where we can clearly observe imprints of overburden anisotropic layers on the seismic response of the target zone. Then I present a simple method to remove the effect of anisotropic overburden to recover reservoir fracture parameters. It involves analyzing amplitude variation with offset and azimuth (AVOA) for the top of reservoir reflector and for a reflector below the reservoir. Seismic CMP gathers are transformed to delay-time vs. slowness (tau-p) domain. We then calculate the ratio of the amplitudes of reflections at the reservoir top and from the reflector beneath the reservoir. The ratios of these amplitudes are then used to isolate the effect of the reservoir interval and remove the transmission effect of the overburden. The methodology is tested on two sets of models - one containing a fractured reservoir with isotropic overburden and the other containing a fractured reservoir with anisotropic overburden. Conventional analysis in the x-t domain indicates that the anisotropic overburden has completely obscured the anisotropic signature of the reservoir zone. When the new methodology is applied, the overburden effect is significantly reduced. The methodology is also applied to an actual PP surface reflection (Rpp) 3D dataset over a reservoir in the Arabian Peninsula. Ellipse-fitting technique was applied to invert for two Fracture parameters: (1) Fracture density and (2) fracture direction. Fracture density inversion results indicate increased fracturing in the anticline structure hinge zone. Fracture orientation inversion results agree with Formation MicroImaging (FMI) borehole logs showing a WNW-ESE trend. This newly developed amplitude ratio method is suitable for quantitative estimation of fracture parameters including normal and tangential “weaknesses” (ΔN and ΔT respectively). Initially, inversion of conventional AVOA for ΔN and ΔT parameters indicates that the ΔN parameter is reliably estimated given an accurate background isotropic parameter estimation derived from borehole logging data. While ΔN parameter inversion is successful, inversion for ΔT parameter from Rpp information is not, presumably due to the dependence of ΔT estimation on many medium parameters for accurate prediction. The ΔN parameter is then successfully recovered when applied to the amplitude ratio values derived from synthetic data. It is important to recognize that ΔN parameter is directly proportional to fracture density and high ΔN values can be attributed to high crack density values. The ΔN parameter inversion is also applied to the amplitude ratios derived from real seismic data. This inversion requires fracture azimuth data input that is obtained from the fracture direction inversion using ellipse-fitting technique. The background Vp/Vs ratio.Item Natural fracture characterization of the New Albany Shale, Illinois Basin, United States(2011-12) Fidler, Lucas Jared; Gale, Julia F. W.; Laubach, Stephen E. (Stephen Ernest), 1955-; Fisher, William L.; Flemings, Peter B.; Fomel, Sergey B.; Olson, Jon E.The New Albany Shale is an Upper Devonian organic-rich gas shale located in the Illinois Basin. A factor influencing gas production from the shale is the natural fracture system. I test the hypothesis that a combination of outcrop and core observations, rock property tests, and geomechanical modeling can yield an accurate representation of essential natural fracture attributes that cannot be obtained from any of the methods alone. Field study shows that New Albany Shale outcrops contain barren (free of cement) joints, commonly oriented in orthogonal sets. The dominant set strikes NE-SW, with a secondary set oriented NNW-SSE. I conclude that the joints were likely created by near-surface processes, and thus are unreliable for use as analogs for fractures in the reservoir. However, the height, spacing, and abundance of the joints may still be useful as guides to the fracture stratigraphy of the New Albany Shale at depth. The Clegg Creek and Blocher members contain the highest fracture abundance. Fractures observed in four New Albany Shale cores are narrow, steeply-dipping, commonly completely sealed with calcite and are oriented ENE-WSW. The Clegg Creek and Blocher members contain the highest fracture abundance, which is consistent with outcrop observations. Fractures commonly split apart along the wall rock-cement interface, indicating they may be weak planes in the rock mass, making them susceptible to reactivation during hydraulic fracturing. Geomechanical testing of six core samples was performed to provide values of Young’s modulus, subcritical index, and fracture toughness as input parameters for a fracture growth simulator. Of these inputs, subcritical index is shown to be the most influential on the spatial organization of fractures. The models predict the Camp Run and Blocher members to have the most clustered fractures, the Selmier to have more evenly-spaced fractures, and the Morgan Trail and Clegg Creek to have a mixture of even spacing and clustering. The multi-faceted approach of field study, core work, and geomechanical modeling I used to address the problem of fracture characterization in the New Albany Shale was effective. Field study in the New Albany presents an opportunity to gather a large amount of data on the characteristics and spatial organization of fractures quickly and at relatively low cost, but with questionable reliability. Core study allows accurate observation of fracture attributes, but has limited coverage. Geomechanical modeling is a good tool for analysis of fracture patterns over a larger area than core, but results are difficult to corroborate and require input from outcrop and core studies.