Microseismic imaging was used to image hydraulic fracturing during a gas well stimulation. Some time after the end of the injection, there was an increase in the seismic deformation rate. Investigation of the frequency-magnitude characteristics during the pumping were consistent with other hydraulic fracture results, although the activity recorded after the end of pumping was more consistent with observations of natural seismic deformation along faults. The ratio of p- to s-wave amplitudes also varied for events recorded during the pumping compared to those occurring after the end of pumping, suggesting a different failure mechanism. In this example, it appears that the hydraulic fracture induced movement on a nearby fault.
Microseismic imaging is a powerful method to map the hydraulic fracture stimulation of a well. Often the spatialtemporal location of induced microseisms is used to image the dynamics of the fracture growth, allowing optimization of the stimulation to maximum reservoir contact. Beyond the hypocentral locations of the microseisms, additional attributes of the microseisms can also be used to improve the imaging of the geomechanical deformation and help refine the interpretation of a fracture network (eg. Maxwell et al, 2007).
In this paper, we present results of the monitoring a hydraulic fracture with sensors in two observation wells. The spatial distribution of the microseisms is first presented to illustrate the fracture. The temporal evolution, strength of the microseisms, frequency-magnitude relationship and finally seismic phase amplitude ratios are then presented to highlight the fact that the stimulation appears to have induced deformation on a near by fault.
Microseismicity was used to image a hydraulic fracture stimulation of a gas well in Western Canada. The well intersected a reverse fault system (Figure 1) with low angle thrust faults ranging in dip from 20-30°. Throw along the faults averages 30m (Figure 2). Sandstones of the formation were deposited in a prograding shoreface system and are composed of lower to upper shoreface sands. Sands are regionally massive, reworked and continuous through out the area. Upper fine to medium sized grained quartz cemented sandstones with silica overgrowths occluding primary porosity dominate the formation. The formation is bound on either side by mudstones and very fine grained interbedded siltstones and burrowed shales that were deposited in an offshore transition environment.
Figure 3 shows the location of induced microseisms recording during the hydraulic fracture stimulation of the gas well. The seismic events define a fairly simple fracture oriented approximately N45E. Two discrete clusters of events are observed, one extending about 100 m around the perforations, and a second cluster about 150 m to the NE. In depth, the event locations cluster close to the depth interval of the open perforations.
Figure 4 shows a time-line of the injection pressure and rate of the hydraulic fracture stimulation, which lasted approximately 80 minutes. During the stimulation, the cumulative seismic moment slowly increased. For each of the microseisms, the source strength was computed as a seismic moment, the log of which is defined as a moment magnitude (conceptually similar to the common Richter scale).