A comprehensive regional investigation of the Eagle Ford Shale linking productivity to porosity-thickness (PHIH), lithology ([Formula: see text]), pore volume (PHIT), organic matter (TOC), and water-saturation ([Formula: see text]) variations has not been presented to date. Therefore, isopach maps across the Eagle Ford Shale play west of the San Marcos Arch were constructed using thickness and log-calculated attributes such as TOC, [Formula: see text], [Formula: see text], and porosity to identify sweet spots and spatial distribution of these geologic characteristics that influence productivity in shale plays. The Upper Cretaceous Eagle Ford Shale in South Texas is an organic-rich, calcareous mudrock deposited during a second-order transgression of global sea level on a carbonate-dominated shelf updip from the older Sligo and Edwards (Stuart City) reef margins. Lithology and organic-matter deposition were controlled by fluvial input from the Woodbine delta in the northeast, upwelling along the Cretaceous shelf edge, and volcanic and clastic input from distant Laramide events to the north and west. Local oxygen minimum events along the South Texas margin contributed to the preservation of this organic-rich source rock related to the Cenomanian/Turonian global organic anoxic event (OAE2). Paleogeographic and deep-seated tectonic elements controlled the variations of lithology, amount and distribution of organic matter, and facies that have a profound impact on production quality. Petrophysical modeling was conducted to calculate total organic carbon, water saturation, lithology, and porosity of the Eagle Ford Group. Thickness maps, as well as PHIH maps, show multiple sweet spots across the study area. Components of the database were used as variables in kriging, and multivariate statistical analyses evaluated the impact of these variables on productivity. For example, TOC and clay volume ([Formula: see text]) show an inverse relationship that is related to production. Mapping petrophysical parameters across a play serves as a tool to predict geologic drivers of productivity across the Eagle Ford taking the geologic heterogeneity into account.
We conducted seismic multiattribute analysis by combining seismic data with wireline logs to determine hydrocarbon sweet spots and predict resistivity distribution (using the deep induction log) within the Austin Chalk and Eagle Ford Shale in South Texas. Our investigations found that hydrocarbon sweet spots are characterized by high resistivity, high total organic carbon (TOC), high acoustic impedance (i.e., high brittleness), and low bulk volume water (BVW), suggesting that a combination of these log properties is required to identify sweet spots. Although the lower Austin Chalk and upper and lower Eagle Ford Shale intervals constitute hydrocarbon-sweet-spot zones, resistivity values and TOC concentrations are not evenly distributed; thus, the rock intervals are not productive everywhere. Most productive zones within the lower Austin Chalk are associated with Eagle Ford Shale vertical-subvertical en echelon faults, suggesting hydrocarbon migration from the Eagle Ford Shale. Although the quality factor (Q) was not one of the primary attributes for predicting resistivity, it nevertheless can serve as a good reconnaissance tool for predicting resistivity, brittleness, and BVW-saturated zones. In addition, local hydrocarbon accumulations within the Austin Chalk may be related to Austin TOC-rich zones or to migration from the Eagle Ford Shale through fractures. Some wells have high water production because the water-bearing middle Austin Chalk on the downthrown side of Eagle Ford Shale regional faults constitutes a large section of the horizontal well, as evidenced by the Q attribute. Furthermore, the lower Austin Chalk and upper Eagle Ford Shale together appear to constitute a continuous (unconventional) hydrocarbon play.
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