Seismic Curvature Predicts (and Microseismic Confirms) Locations of Tectonic Fractures in the Fort Worth Basin
Successful horizontal wells, in terms of flow rates and Expected Ultimate Recoveries, in the Barnett Shale depend on highly effective hydraulic stimulation of the ultra low permeability (nanodarcy) mudstone. A priori knowledge of the locations of natural (tectonic) fracture swarms leads to optimum placement of the wells in the first place and to optimum positioning of injection points for multi-stage, large volume hydraulic stimulation.
Curvature processing of 3-D seismic data may be used to identify subtle structures-anticlines, synclines, and flexures-which are likely locations of natural tectonic fracturing. These zones would be relatively weak and are likely to open easily during stimulation and thereby provide preferred conduits for flow of the stimulation fluid. Microseismic monitoring during stimulation gives accurate information about the stimulation fluid travel path and the occurrence of opening fractures.
In this paper, we will show results of interpretation of predrill curvature processing of 3-D seismic data to locate tectonic fracture swarms and of the subsequent downhole microseismic monitoring of a stimulation. We will shows that the movement of the hydraulic simulation fluid occurs preferentially along the trends of the natural fracture swarms as predicted by the initial curvature processing. The concept of using one seismic method (curvature analysis) to predict fracture swarm locations and then using a second method (down hole or surface microseismic monitoring) to verify that prediction to provide quantitative data that can be used to determine Estimated Ultimate Recovery from a well is quite profound.
AAPG Search and Discovery Article #90090©2009 AAPG Annual Convention and Exhibition, Denver, Colorado, June 7-10, 2009