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The hydraulic fractures typically propagate parallel to the maximum stress direction in
the reservoir. In areas of low stress differences, the hydraulic fracture pattern can be quite
complex, as there is no preferential direction for the fracture to grow, in contrast with areas
of high stresses, where the hydraulic fracture grows parallel to the maximum stress direction.
Figure I.2 shows two examples of microseismic mapping results following hydraulic fractur-
ing procedures in Texas: an example from the Barnett shale gas horizontal well showing a
complex fracture geometry (right), and the other from tight gas sands in a vertical well in
the Cotton Valley formation, which shows a simple fracture geometry (left).
Microseismic mapping with borehole or surface sensors can be used to distinguish
between reactivated natural faulting and hydraulic fracture events, through
b
value analysis
(see Appendix D). Hydraulic fracture wells are often drilled to avoid large natural faults
distinguished from three-dimensional surface seismic images, as faults can “steal” fractur-
ing fluid and divert fluids away from the formation targeted for hydraulic fracturing. An
example of this issue was discussed by Wessels et al. (2011), where a through-going fault
was reactivated during hydraulic fracturing (Figure I.3).
REFERENCES
Maxwell, S.C., J. Rutledge, R. Jones, and M. Fehler. 2010. Petroleum reservoir characterization using downhole microseismic
monitoring.
Geophysics
75(5):75A129-75A137.
Warpinski, N.R., R.C. Kramm, J.R. Heinze, and C.K. Waltman. 2005. Comparison of single- and dual-array microseismic
mapping techniques in the Barnett Shale. Presented at the Society of Petroleum Engineers Annual Technical Confer-
ence and Exhibition, Dallas, TX, October 9-12.
Wessels, S.A., A. De La Pena, M. Kratz, S. Williams-Stroud, and T. Jbeili. 2011. Identifying faults and fractures in uncon-
ventional reservoirs through microseismic monitoring.
First
Break
29(7):99-104.
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