<?xml version='1.0' encoding='utf-8'?>
<oai_dc:dc xmlns:dc="http://purl.org/dc/elements/1.1/" xmlns:oai_dc="http://www.openarchives.org/OAI/2.0/oai_dc/" xmlns:xsi="http://www.w3.org/2001/XMLSchema-instance" xsi:schemaLocation="http://www.openarchives.org/OAI/2.0/oai_dc/ http://www.openarchives.org/OAI/2.0/oai_dc.xsd">
  <dc:contributor>Justin E. Birdwell</dc:contributor>
  <dc:contributor>Stanley T. Paxton</dc:contributor>
  <dc:creator>Lauri A. Burke</dc:creator>
  <dc:date>2022</dc:date>
  <dc:description>&lt;div class="article-section-wrapper js-article-section js-content-section  "&gt;&lt;p&gt;Traditional petrophysical methods to evaluate organic richness and mineralogy using gamma-ray and resistivity log responses are not diagnostic in source rocks. We have developed a deterministic, nonproprietary method to quantify formation variability in total organic carbon (TOC) and three key mudrock mineralogical components of nonhydrocarbon-bearing source rock strata of the Eagle Ford Group by developing a set of log-derived multimineral models calibrated with Fourier transform infrared spectroscopy core data from the research borehole U.S. Geological Survey Gulf Coast 1 West Woodway. We determined that bulk density response is a reliable indicator of organic content in these thermally immature, water-bearing source rocks. Multimineral findings indicate that a high degree of laminae-scale mineralogical heterogeneity exists due to thinly interbedded carbonate cements amid clay-rich mudstone layers. The lower part of the Eagle Ford Group contains the highest average TOC content (4.7&amp;nbsp;wt%) and the highest average carbonate volume (64.1&amp;nbsp;vol%), making it the optimal target in thermally mature areas for source-rock potential and hydraulic-fracture placement. In contrast, the uppermost portion of the Eagle Ford Group contains the highest average volume of clay minerals (42.6&amp;nbsp;vol%), which increases the potential for wellbore stability issues. Petrophysical characterization reveals that porosity is approximately 30% in this relatively uncompacted formation. In this thermally immature source rock, water saturation is nearly 100% and no free hydrocarbons were observed on the resistivity logs. No evidence of borehole ellipticity was observed on the three-arm caliper log, and horizontal stresses are presumed to be directionally uniform in the vicinity of this near-surface wellbore. This shallow wellbore has a temperature gradient of 1.87°F/100&amp;nbsp;ft (16.3°C/km) and is likely influenced by earth surface heating.&lt;/p&gt;&lt;/div&gt;</dc:description>
  <dc:format>application/pdf</dc:format>
  <dc:identifier>10.1190/INT-2021-0094.1</dc:identifier>
  <dc:language>en</dc:language>
  <dc:publisher>Society of Exploration Geophysicists</dc:publisher>
  <dc:title>Multimineral petrophysics of thermally immature Eagle Ford Group and Cretaceous mudstones, U.S. Geological Survey Gulf Coast 1 research wellbore in central Texas</dc:title>
  <dc:type>article</dc:type>
</oai_dc:dc>