The Barnett Shale in the Fort Worth Basin is one of the most important resource plays in the USA. The total organic carbon (TOC) and brittleness can help to characterize a resource play to assist in the search for sweet spots. Higher TOC or organic content are generally associated with hydrocarbon storage and with rocks that are ductile in nature. However, brittle rocks are more amenable to fracturing with the fractures faces more resistant to proppant embedment. Productive intervals within a resource play should therefore contain a judicious mix of organics and mineralogy that lends to hydraulic fracturing. Identification of these intervals through core acquisition and laboratory-based petrophysical measurements can be accurate but expensive in comparison with wireline logging. We have estimated TOC from wireline logs using Passey’s method and attained a correlation of 60%. However, errors in the baseline interpretation can lead to inaccurate TOC. Using nonlinear regression with Passey’s TOC, normalized stratigraphic height, and acquired wireline logs, the correlation increased to 80%. This regression can be applied to uncored wells with logs to estimate TOC, and we used it as a ground truth in integrated analysis of seismic and well log data. The brittleness index (BI) is computed based on core Fourier transform infrared mineralogy using Wang and Gale’s formula. The correlation between core BI and estimated BI using elastic logs ([Formula: see text], [Formula: see text], [Formula: see text], [Formula: see text], and [Formula: see text]) combined with wireline logs was 78%. However, this correlation decreases to 66% if the BI is estimated using only wireline logs. Therefore, the later serves as a less reliable proxy. We have correlated production to volumetric estimate of TOC and brittleness by computing distance-weighted averages in 120 horizontal wells. We have obtained a production correlation of 38% on blind wells, which was encouraging, suggesting that the geologic component in completions provides an important contribution to well success.
Seismic attenuation, generally related to the presence of hydrocarbon accumulation, fluid-saturated fractures, and rugosity, is extremely useful for reservoir characterization. The classic constant attenuation estimation model, focusing on intrinsic attenuation, detects the seismic energy loss because of the presence of hydrocarbons, but it works poorly when spectral anomalies exist, due to rugosity, fractures, thin layers, and so on. Instead of trying to adjust the constant attenuation model to such phenomena, we have evaluated a suite of seismic spectral attenuation attributes to quantify the apparent attenuation responses. We have applied these attributes to a conventional and an unconventional reservoir, and we found that those seismic attenuation attributes were effective and robust for seismic interpretation. Specifically, the spectral bandwidth attribute correlated with the production of a gas sand in the Anadarko Basin, whereas the spectral slope of high frequencies attribute correlated with the production in the Barnett Shale of the Fort Worth Basin.
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