Reservoir Type and Fracture Connectivity in the Austin Chalk

Krystal Pearson
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The Cretaceous Austin Chalk is a low-porosity, low-permeability carbonate reservoir with a microporous matrix that requires large connected fracture systems to store and produce hydrocarbons. The underlying Cretaceous Eagle Ford Shale is the main source of Austin Chalk hydrocarbons. Kerogen type is dominantly oil-prone, and source rock quality varies both laterally and vertically. The Eagle Ford Shale entered the oil generation window sometime in the Paleogene to Neogene, which postdates the creation of the fractured reservoirs, and allows for the emplacement of oil into these reservoirs immediately after generation. Giddings, Pearsall, and Masters Creek fields are the largest in the play, and overlie the present-day Eagle Ford oil window. Fractures act as migration pathways for hydrocarbons and fracture density and connectivity are highly variable. Fractures are concentrated on downthrown fault blocks and within grabens, and are connected in a strike direction rather than in a dip orientation. Austin Chalk fields updip from mature Eagle Ford Shale (e.g. Luling-Branyon, Buchanan, and Fentress) require updip migration of oil through these systems. In 2010, the U.S. Geological Survey assessed the Austin Chalk for total technically recoverable hydrocarbons using both conventional and continuous (unconventional) methodologies. Conventional reservoirs contain clearly defined seals and traps (faults, structures, and stratigraphic pinchouts), typically display high matrix permeability, and have well-delineated hydrocarbon-water contacts. Continuous reservoirs, in contrast, are regional in extent, have diffuse boundaries and low permeabilities, and lack obvious seals, traps, and hydrocarbon-water contacts. Continued...

AAPG Search and Discovery Article #90167©2013 GCAGS and GCSSEPM 63^rd Annual Convention, New Orleans, Louisiana, October 6-8, 2013