The natural gas-bearing transgressive systems tract (TST) Vicksburg interval in TCB Field, South Texas, was the focus of a comprehensive petrophysical evaluation. This interval was deposited in a transgressive shallow marine setting and is composed of thinly bedded and laminated silty, very fine-grained sandstones, siltstones, and shales. The TST interval was selected for its specific sedimentary features and compositional complexity that are typical of low-resistivity/low-contrast shaly sandstone reservoirs.

The goal was to develop improved formation evaluation techniques for this type of reservoir. Cores were sampled for thin-section, X-ray, SEM, φ-k, capillary pressure, and cation exchange capacity (CEC) analyses. Array induction, gamma ray, neutron-density, micro-imaging, and nuclear magnetic logs were calibrated to cores. High-resolution logs allowed the recognition of reservoir and non-reservoir facies thicker than 1 ft, while micro-imaging resolved beds down to the one-half inch scale. High-resolution density porosity measurements were very close to measured core porosity values and used to estimate total porosity. The low- resistivity signatures of sandstones are mainly generated by the abundance of clays, especially illite/smectite mixed-layer clays. The Pickett crossplot technique was used to derive m, n and Rw values for water saturation (Sw) calculation. Resistivity modeling using Waxman-Smits and Modified Dual-Water methods also yielded m and n values that agreed with those from the Pickett technique. Reliable results were achieved using the simple Archie equation modified using the newly estimated m, n and Rw values. Modified Archie, Waxman-Smits and Modified Dual-Water methods yielded Sw values that correlated best to those from core analyses.

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