Seismic multiattribute analysis for shale gas/oil within the Austin Chalk and Eagle Ford Shale in a submarine volcanic terrain, Maverick Basin, South Texas

2013 ◽  
Vol 1 (2) ◽  
pp. SB61-SB83 ◽  
Author(s):  
Osareni C. Ogiesoba ◽  
Ray Eastwood
Keyword(s):  
High Water ◽  
South Texas ◽  
High Resistivity ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Austin Chalk ◽  
Bulk Volume ◽  
Multiattribute Analysis ◽  
Quality Factor Q ◽  
Sweet Spots

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.

Regional assessment of the Eagle Ford Group of South Texas, USA: Insights from lithology, pore volume, water saturation, organic richness, and productivity correlations

2016 ◽  
Vol 4 (1) ◽  
pp. SC125-SC150 ◽  
Author(s):  
Ursula Hammes ◽  
Ray Eastwood ◽  
Guin McDaid ◽  
Emilian Vankov ◽  
S. Amin Gherabati ◽  
...  
Keyword(s):  
Organic Matter ◽  
Pore Volume ◽  
Water Saturation ◽  
Production Quality ◽  
South Texas ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
The North ◽  
The Impact ◽  
Sweet Spots

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.

Biostratigraphy of the Cenomanian–turonian Eagle Ford Shale of South Texas

2017 ◽  
Vol 47 (2) ◽  
pp. 105-128 ◽  
Author(s):  
Christopher M. Lowery ◽  
R. Mark Leckie
Keyword(s):  
Carbonate Platform ◽  
Academic Research ◽  
Rio Grande ◽  
South Texas ◽  
Published Data ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Oceanic Anoxic Event ◽  
Austin Chalk ◽  
San Marcos

Abstract The Cenomanian–Turonian Eagle Ford Shale of south Texas occupies an important gateway between the Western Interior Seaway (WIS) of North America and the Gulf of Mexico. While the Eagle Ford north of the San Marcos Arch and its stratigraphic equivalents to the east of the Sabine Arch are shallow-water sediments dominated by terrigenous clastics, the more distal localities in south Texas are dominated by hemi-pelagic carbonates draped over an Early Cretaceous carbonate platform, called the Comanche Platform, and adjacent submarine plateaus and basins. This region was strongly affected by major oceanographic changes during the Cenomanian-Turonian, particularly a significant transgression that drove localized upwelling and organic matter burial in the Lower Eagle Ford prior to the global Oceanic Anoxic Event 2 (OAE2). These pre-OAE2 organic-rich shales are the basis of Eagle Ford shale gas play, which has spurred commercial and academic research into many aspects of the geology of the Eagle Ford Group. Much of this research has been fairly locally focused, and little effort has been made to understand the timing of events across the platform. We compared new data from three study sites across south Texas—Lozier Canyon in Terrell Co.; Bouldin Creek in Travis Co., near the San Marcos Arch in the center of the Comanche Platform; and Swift Energy's Fasken Core in Webb Co., off the platform on the Rio Grande Submarine Plateau—as well as published data from near Big Bend National Park on the western margin, and from Atacosta and Karnes counties on the eastern margin. Using these data we document the occurrence of key foraminiferal species across the platform and present a regional biostratigraphic scheme incorporating five global planktic foraminiferal zones (and contemporaneous occurrences that may serve as proxies for the zonal markers, which tend to be rare in Texas) and four local origination or acme events that serve as useful secondary markers. The succession of events is: 1) highest occurrence (HO) Favusella washitensis, 2) lowest occurrence (LO) Rotalipora cushmani, 3) “Benthonic Zone”, 4) HO R. cushmani and/or Thalmaninella greenhornensis, 5) “Heterohelix shift”, 6) LO “Anomalina W”, 7) LO Helvetoglobotruncana helvetica, 8) HO H. sp., and 9) LO Dicarinella concavata. Overall, we show that lithologic and geochemical trends through most of the Eagle Ford, particularly the oxygenation at the onset of OAE2 and the concurrent shift to more carbonate-rich lithologies, are synchronous across the Comanche Platform. However, the transition from the Eagle Ford Group to the Austin Chalk varies in age. While Austin Chalk deposition began in the middle Turonian Marginotruncana schneegansi Zone on the Rio Grande Submarine Plateau, a transgressive surface on the Comanche Platform (known as the “Rubble Zone” in central Texas) represents a condensed interval at the top of the Eagle Ford that ends in the upper Turonian D. concavata Zone. This is part of a transgressive disconformity that extends north through the WIS, where it is associated with the Juana Lopez Calcarenite.

RESERVOIR SCALE CHEMOSTRATIGRAPHY AND FACIES MODELING USING HIGH SAMPLE RATE GEOPHYSICAL SCANS OF WHOLE CORE

2021 ◽  
Author(s):  
John J. Degenhardt ◽  
◽  
Safdar Ali ◽  
Mansoor Ali ◽  
Brian Chin ◽  
...  
Keyword(s):  
Machine Learning ◽  
Mechanical Properties ◽  
High Resolution ◽  
Operating Characteristics ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Vertical Heterogeneity ◽  
Austin Chalk ◽  
Sample Rate ◽  
Petrophysical Logs

Many unconventional reservoirs exhibit a high level of vertical heterogeneity in terms of petrophysical and geo-mechanical properties. These properties often change on the scale of centimeters across rock types or bedding, and thus cannot be accurately measured by low-resolution petrophysical logs. Nonetheless, the distribution of these properties within a flow unit can significantly impact targeting, stimulation and production. In unconventional resource plays such as the Austin Chalk and Eagle Ford shale in south Texas, ash layers are the primary source of vertical heterogeneity throughout the reservoir. The ash layers tend to vary considerably in distribution, thickness and composition, but generally have the potential to significantly impact the economic recovery of hydrocarbons by closure of hydraulic fracture conduits via viscous creep and pinch-off. The identification and characterization of ash layers can be a time-consuming process that leads to wide variations in the interpretations that are made with regard to their presence and potential impact. We seek to use machine learning (ML) techniques to facilitate rapid and more consistent identification of ash layers and other pertinent geologic lithofacies. This paper involves high-resolution laboratory measurements of geophysical properties over whole core and analysis of such data using machine-learning techniques to build novel high-resolution facies models that can be used to make statistically meaningful predictions of facies characteristics in proximally remote wells where core or other physical is not available. Multiple core wells in the Austin Chalk/Eagle Ford shale play in Dimmitt County, Texas, USA were evaluated. Drill core was scanned at high sample rates (1 mm to 1 inch) using specialized equipment to acquire continuous high resolution petrophysical logs and the general modeling workflow involved pre-processing of high frequency sample rate data and classification training using feature selection and hyperparameter estimation. Evaluation of the resulting training classifiers using Receiver Operating Characteristics (ROC) determined that the blind test ROC result for ash layers was lower than those of the better constrained carbonate and high organic mudstone/wackestone data sets. From this it can be concluded that additional consideration must be given to the set of variables that govern the petrophysical and mechanical properties of ash layers prior to developing it as a classifier. Variability among ash layers is controlled by geologic factors that essentially change their compositional makeup, and consequently, their fundamental rock properties. As such, some proportion of them are likely to be misidentified as high clay mudstone/wackestone classifiers. Further refinement of such ash layer compositional variables is expected to improve ROC results for ash layers significantly.

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