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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 fracturing 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” fracturing 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 Conference 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 unconventional reservoirs through microseismic monitoring. First Break 29(7):99-104.



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