--> --> Abstract: Predicting Hydraulically Induced Fractures Using Acoustic Impedance Inversion Volumes: A Barnett Shale Formation Example, by Xavier E. Refunjol, Joel H. Le Calvez, and Kurt J. Marfurt; #90124 (2011)

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Making the Next Giant Leap in Geosciences
April 10-13, 2011, Houston, Texas, USA

Predicting Hydraulically Induced Fractures Using Acoustic Impedance Inversion Volumes: A Barnett Shale Formation Example

Xavier E. Refunjol1; Joel H. Le Calvez2; Kurt J. Marfurt3

(1) The University of Oklahoma, currently Swift Energy, Houston, TX.

(2) Schlumberger, Dallas, TX.

(3) The University of Oklahoma, Norman, OK.

Once considered only as source rocks and seals, shale formations are now also considered as tight-porosity and low-permeability unconventional gas reservoirs. The classification as a reservoir is mainly technology- and economics-driven. Major gas (and minor oil) production from these plays is facilitated by massive hydraulic fracturing treatments that increase permeability and help to reactivate natural fractures. Stimulation ultimately enhances reservoir drainage, yielding economically viable hydrocarbon production. Natural faulting and fracturing are critical factors controlling present day stress distribution, which in turn influences hydraulically induced fracture system development. Most predictive models used to estimate recovery in microseismicity monitoring wells are based on assumptions that lead to oversimplified fracture network geometry. To avoid such assumptions, and better understand the created fracture geometry, borehole-based induced microseismicity monitoring may be used.

Hydraulically induced fracture networks mapped in various formations around the world using borehole-based microseismic monitoring techniques correlate closely to stress states at various scales. Mapped fracture systems generally tend to propagate perpendicularly or nearly perpendicularly to the minimum horizontal stress while influenced by local and regional structural features. However, the heterogeneous and anisotropic mineralogical composition of the shale formation results in variable fracture gradients and fractured zones. To characterize the variations of rock properties within such formations, we generated seismic inversion volumes from a 14-square-mile seismic survey acquired over the Barnett Shale within the Fort Worth basin using P- and S-impedance and Lamé parameters from density, shear, and compressional velocity logs. We show that the locations of microseismic events correlate to specific values of the inverted surface seismic properties. Fractured zones correlate to low density and low P- and S-impedance values. While impedance characterizes the matrix properties of the Barnett Shale, Lamé parameters shed light on the extent of the fracture system into gas-bearing zones.

This initial correlation suggests that 3D surface seismic-derived inversion volumes may serve as a tool to help design hydraulic stimulation programs using a priori knowledge of the most likely fracture propagation trends and failure loci.