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Abstract: Predicting Fractured Reservoir Location and Characteristics in the West Texas Permian Basin

TUNCAY, KAGAN, GONCA OZKAN, ANTHONY PARK, and PETER ORTOLEVA, Laboratory for Computational Geodynamics; THOMAS HOAK, Kestrel Geoscience; KENNETH SUNDBERG, Phillips Petroleum Company

Natural fracturing in the West Texas Permian Basin arises from vug-related microcracking, faulting, flexure, and fluid overpressure. To predict fracturing, a basin model coupling diagenesis, hydrology, and rock deformation is essential. We have developed such a model and are applying it to the West Texas Permian Basin.

Our model accounts for:

(i) high fluid pressure facilitates rock failure through effective stress;

(ii) diagenesis enhances or degrades rock strength;

(iii) basin compression/extension and uplift/subsidence cause faulting and flexure of sediments; and

(iv) vugs can collapse or induce microfractures.

Our three-dimensional, finite element rock deformation, hydrologic, and diagenesis model shows how a fracture zone varies in time as the Central Platform is uplifted and the Midland and Delaware Basins formed. The location, timing, and extent of fracturing depend on detailed tectonic, diagenetic, and hydrologic history. Zones where vug collapse or nearby fracturing occur are predicted. The zone of vug-related fracturing migrates within the basin over time. The location of this and other failure or hydrofracture zones depends on the basin tectonic, thermal, and sedimentary history. Fluid pressure variations are key in defining potential hydrofracture zones. This suggests that production and associated fluid pressure decrease may actually enhance permeability leading to enhanced production in low matrix permeability reservoirs.

As our model appears to capture the temporal evolution of fracture zones across a basin, we believe it is an important new tool for basin exploration and production optimization.

AAPG Search and Discovery Article #90937©1998 AAPG Annual Convention and Exhibition, Salt Lake City, Utah