ABSTRACT

The Austin and Buda formations have been the target of active exploration due to the increased oil prices. These reservoirs are almost totally dependent on natural fracturing for productivity. Matrix permeability is normally less than 0.5 md. The natural fracturing is present throughout the vertical interval with fractured density ranging from one per foot to more than 25 fractures per foot. These micro-fractures have widths ranging from 0.1 mm to 0.4 mm. Oil saturations measured from routine core analysis vary in the Austin and Buda formations from zero to 60 percent and are erratically distributed throughout the formation. Procedures for measuring fracture density, dip angle, and dip direction and criteria to distinguish between natural and induced fractures have been formulated for over 7,000 ft of recovered and analyzed core from these formations. Results of these core and fracture analyses indicate the following criteria must be present to successfully complete an oil well: (1) the fracture density must be in excess of one per foot; (2) residual oil saturation in the matrix must be in excess of 10 percent; (3) there must be some indication of matrix permeability, normally 0.01 md. It is apparent that to have sustained production from the Austin and Buda, oil saturation must be present in the matrix as the fracture volume is extremely small and is rapidly depleted. Relationship between fracture width, fracture block height, porosity, and permeability have been developed from theoretical calculations and appear to be confirmed by well performance. These calculations indicate that a fracture porosity of 0.1 to 0.25 percent is common throughout the Austin Chalk trend. These data also have been used to calibrate fracture-finding logs and to assist in the development of completion programs.