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

Abstract

Abstract The lower Tertiary Wilcox, Yegua and Vicksburg formations are prolific natural gas plays in South Texas that have been extensively drilled and produce 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 the 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 which 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 allows 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 easily identified 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. Introduction Formation Evaluation in the South Texas Wilcox, Yegua and Vicksburg sands is problematic due to the influence of the varying clay volume, average grain size, and hydrocarbon type on the logging measurements. In these South Texas shaly sands, the volume of clay minerals has traditionally been approximated from gamma ray, spontaneous potential, or density-neutron logs. Each of these methods has serious limitations. For example, if non-clay sources of radioactivity are present, estimates of clay volume from gamma ray will be too high, resulting in reduced estimates of effective porosity, pessimistic reserve calculations and an overall reduction in the valuation of the reservoir's potential. The clay volume also has an adverse affect on the ability to locate gas zones using the neutron-density crossover technique. The crossover is suppressed in gas zones in proportion to the amount of clay present. The presence of mud filtrate invasion will also suppress the neutron-density crossover in gas zones. Background Our ability to accurately calculate reservoir properties such as porosity, fluid saturation, permeability and capillary bound water from downhole logging measurements requires knowledge of the types and abundance of different minerals within the reservoir. Variations in elemental and mineralogical rock properties directly effect matrix density, cation exchange capacity, natural gamma radiation, matrix capture cross section, thermal neutron absorption and surface relaxivity.