Nanopore and Fracture Duel Pore Network in the Upper Cretaceous Buda Formation, Dimmit Co., Texas

Abstract

The Buda section is a well-explored fractured chalky reservoir. It is composed of deeper water carbonate strata that had periodic influxes of argillaceous material. The depositional setting on the drowned Lower Cretaceous shelf was well oxygenated based on high-level of bioturbation and fossil diversity. Lithofacies are fossiliferous calcisphere/globigerinid lime wackestone/packstone with argillaceous seams. The lime mud (much of it is coccoliths) was deposited by suspension and reworked by bottom currents and bioturbation. Some of the mud was resedimented by mud flows containing soft-mud clasts and sponges. Mineralogy is calcite containing dolomite crystals and quartz silt. The argillaceous material is interpreted to be associated with storm-return flows. Tectonic fractures are the dominant producing pore network; however an oil saturated nanopore network also exists. As observed using Ar-ion milled samples on the SEM, pore diameters within the matrix range in size from ~10 nm up to 1 micron. Nanopores occur as patches in the matrix or in transported mud clasts. SEM image analysis shows that the nanopores are the incomplete cementation of the original void space between coccolith hash (now microrhombs). The microrhombs range between 0.5 to 4 microns. They are euhedral and show growth interference and resulting interlocking of crystals. The nanopores have triangular shapes characteristic of crystal growth into a pore. Within some of the pores are submicrometer clay crystals that further divide the intercrystalline nanopores into finer pores. Matrix reservoir quality as noted in the Enercrop #1H Willerson well is very low according to conventional core-plug analysis. Most porosity values are less than 5% and most permeability values are between 0.001 to 0.01 md. An interesting observation is that mud-flow zones generally have higher porosities than in-place matrix, but both have similar permeabilites. Calculated pore throat mean radii is generally less than 50 nm with several samples having pore throat mean radii of ~5 nm. These small pore throat sizes will be very restrictive to oil flow. A six-month production-decline curve shows a rapid decline in production; this is characteristic of a fractured reservoir. Matrix porosity may contribute some oil into the large surface area of fractures, but not enough to significantly contribute to enhanced production that keeps the decline curve from decreasing rapidly.

AAPG Datapages/Search and Discovery Article #90216 ©2015 AAPG Annual Convention and Exhibition, Denver, CO., May 31 - June 3, 2015