Three-dimensional seismic volumes from the central Fort Worth Basin display roughly circular collapse chimneys that extend vertically about 800 m from the Ordovician Ellenburger Formation to the Atokan ͑middle Pennsylvanian͒ Caddo Limestone. Collapse chimneys in carbonates may be caused by subaerial karst, hydrothermal, or tectonic extensional processes. We use 3D multitrace geometric attributes including coherence, volumetric curvature, and energyweighted, coherent amplitude gradients to investigate details of the origin of these structures. The Ordovician Ellenburger surface resembles a subaerial karst landscape of cockpits, dolines, and frying-pan valleys, while resistivity-based wireline image logs record 50 m of karst breccia facies. However, images from coherence and long-wavelength most-positive and most-negative-curvature volumes show many of the 800-m collapse features are associated with basement faults or with subtle Pennsylvanian and younger tectonic features, rather than with intra-Ellenburger collapse. We hypothesize that although the Ellenburger surface does contain a subaerial karst overprint, the first-order control on the formation of the vertically extensive collapse chimneys is bottoms-up tectonic-induced extensional collapse. Although these collapse chimneys have been affected by burial fluid diagenesis, the main consequence of burial fluid flow may be limited to the documented cementation of macrofractures. The apparent dominance of tectonic extension processes over subaerial karst and hydrothermal processes has basinwide implications for distribution of fractures, late-stage cements, and reservoir development and compartmentalization.
A comprehensive site study carried out in an Upper Devonian shale gas reservoir at a site in southern West Virginia provided data to test a geomechanical model for stimulation of the Huron formation. Using a model in which natural fractures provide the primary conduits for production and are the major target for stimulation, and in which stimulation triggers shear slip on those pre-existing fractures, we were able to predict the shape of the reservoir volume stimulated by injection of high-quality foam and to match injection flow rates and pressures using a dual porosity dual permeability finite-difference flow simulator with anisotropic, pressure-sensitive reservoir properties. The resulting calibrated model matched both the relative contribution of the individual stages measured by production logging and the early-life well production. This suggests that similar models may in the future provide earlier and better production predictions, guidance for completion and stimulation design, and recommendations to minimize production decline and maximize well value.
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