Microseismic monitoring of hydraulic fracture stimulations is used to determine the extent of fractured rock resulting from the treatment by mapping the locations of induced microseismic events. Usually the geometry of the event locations is used to infer fracture orientations; e.g. trends of microseismic events concentrated along a particular azimuth (or with a planar distribution in 3D) can indicate fracturing along a plane with that orientation. In this study we use additional parameters extracted from induced microseismic events (source mechanisms) to determine the specific fracturing behavior and compare them with independent observations from an FMI log in the treatment well. In a horizontal well located in the mid-Continental USA, we present the results of source mechanism analysis for the best signal-to-noise events triggered by the fracture stimulation treatment. The microseismic events with source mechanisms have failure planes with very similar orientations to natural fractures in the image log. Our results are consistent with the reactivation of natural fractures during the stimulation treatment, suggesting that it is possible to determine natural fracture orientations in the reservoir in cases where image logs are not available. In addition, the microseismic event source mechanisms allow fracture characterization away from the wellbore, providing critical constraints for building fractured reservoir models.
Upscaling or downscaling of measured data is a formidable challenge in characterization of reservoir properties and significant assumptions need to made in order to bridge measurements that were acquired on different scales. This is particularly true for correlating wellbore measurements and seismic measurements (e.g. Prioul and Jocker, 2009). A successful characterization of natural fractures plays an important role in modeling fluid transport through reservoir formation. Analysis of in-situ data from borehole images (e.g. FMI or acoustic image logs) is commonly done to identify the presence and orientations of natural fractures (Wu and Pollard, 2002). Measurements made at the borehole are usually extrapolated to larger scale properties such as seismic anisotropy or coherence in order to characterize reservoir properties between boreholes (Lees, 1998). As fractures are a natural chaotic system associated with significant spatial variability, a key question in those extrapolations is the feasibility of extrapolating measurements of fractures from wellbores on the centimeter scale to fractures in the reservoir with a length scale of hundreds of meters. Rutledge and Phillips (2003) proposed that the orientation of natural fractures controls orientations of failure planes of induced microseismic events. In their model, small-scale natural fractures coalesce to form larger faults of several meters. They observed strike-slip source mechanisms on vertical failure planes for induced microseismic events striking nearly parallel to natural fractures in Cotton Valley rocks (Dutton et al, 1991). However, because Rutledge and Phillps observations were based on inversion from a small number of geophones in two monitoring boreholes, they were able to determine only a composite (average) focal mechanism from many events grouped on the assumption of mechanism similarity, raising significant doubts about the accuracy of the observed results (e.g. Sileny et.al. 2009).
