A New Formation-Evaluation Technique for the Lower Tertiary in South Texas—Predicting Production in Low-Permeability, Fine-Grained Sandstones

Abstract

Summary The lower Tertiary Wilcox, Yegua, and Vicksburg formations are prolific natural gas plays in south Texas that have been extensively drilled and produced from low-permeability, fine-grained sandstones. It is not unusual to encounter several potential pay zones in each well. What is lacking is a proven formation-evaluation method to determine the highest-productivity water-free producing zones from multiple intervals that can be casually identified on the logs as hydrocarbon-bearing. Connate-water resistivity (Rw) determination is not a major problem, given that many water-bearing sands are usually present. Accurately estimating true clay content, porosity, irreducible water volumes, and permeability present the greatest challenges. A new spectroscopy-based petrophysical interpretation methodology has been developed that makes use of several unique measurements, namely quantitative elemental concentrations and lithology logs obtained from capture gamma ray spectroscopy devices in open or cased wells. These measurements allow us to more accurately define the clay content, mineralogy, and matrix properties of each potential zone. One significant finding obtained from these measurements is the occurrence of calcite cements detected in many sands that cause a pessimistic density porosity to be computed if not accounted for. This calcite cementation appears to vary dramatically in a lateral sense, indicating that its presence should not be used to condemn an entire layer as being too tight for production, nor provide irrefutable evidence of the expected ability of the layer to contain a hydraulic fracture. The enhanced elemental and mineralogical analyses provided by the spectroscopy measurements also allow for more accurate bulk volume irreducible water calculations and a means to correct the neutron porosity for clay and matrix effects. By comparing irreducible water volume to bulk volume hydrocarbon, an accurate prediction of water production can be determined. Oil- and gas-bearing intervals can be identified easily from crossover of the matrix-corrected neutron porosity when used in conjunction with the matrix-corrected density porosity. Results are illustrated with several case studies from wells recently drilled and now producing from the Wilcox, Yegua, and Vicksburg formations.