Microseismicity induced by hydraulic fracture stimulation of a horizontal well was mapped with a near-surface buried array. Distinct linear trends of events were not parallel to the direction of fast shear wave polarization measured in the reservoir with a crossed-dipole anisotropy tool. Analysis of core from a nearby well revealed numerous calcite-filled fractures that did not induce shear wave polarization, but did significantly impact the failure behavior of the reservoir rock during the stimulation treatment. Hydraulic fracture simulation with DFN modeling and source mechanism analysis supports the interpretation of reactivated existing fractures rather than the formation of hydraulically-induced tensile fractures.
The development of linear trends of microseismicity during hydraulic fracture stimulation treatments has been typically interpreted to be indicators of the location of induced hydraulic fractures forming parallel to the maximum stress direction in the reservoir. Induced fractures failing in mode I tensile failure may not generate strong enough microseismic signal to be detected via microseismic monitoring methods, so often the microseismic events are interpreted to be the result of a shear failure “halo” around the hydraulic fracture or reactivation of intersecting natural fractures [1, 2]. Analysis of microseismic monitoring results acquired using an array of geophones buried in a grid over a wide area above the well allows collection of microseismicity without a directional bias [Fig 1.]. In addition, the wide aperture of the array provides coverage to detect signal at all azimuths so that it is possible to determine the full source mechanism for all events with sufficient energy detected by the array [3, 4]. Source mechanism analysis shows that the failure planes of the events are parallel to the microseismic event trend, but the microseismic event trend is not parallel to the reservoir maximum horizontal stress interpreted from a crossed-dipole sonic log.