One of the key factors in economic development of shale and other unconventional reservoirs is effective hydraulic fracturing. Much of the current understanding of hydraulic stimulation of shales can be traced back to the Barnett Shale, where well engineering eventually led to a successful combination of massive water fracs, horizontal drilling and microseismic monitoring. Microseismicity associated with hydraulic fracturing is the key technology that provides an image of the subsurface fracture geometry. In the Barnett, microseismic was particularly instrumental to the realization that the massive water fracs were stimulating a complex fracture network containing intersecting fractures in various orientations, which results in an efficient drainage system with a large surface contact area to the low permeability reservoir. Indeed microseismic data is often the primary subsurface geophysical imaging data. With the recent ‘shale gale’ and spread of interest to find Barnett analogues through first North America and around the globe, microseismic monitoring has become the de facto fracture mapping technology to image, control and ultimately optimize the fracture networks in these diverse reservoirs and geological settings.

Fig. 01
Contours of estimated reservoir pressure decline after 20 years of production, simulated using a complex fracture model calibrated against microseismic data monitored during a multi-stage horizontal well hydraulic fracture.

This presentation will include a look back at the impact of microseismic on shale development, using case studies to demonstrate the advancement of microseismic applications. As with any microseismic frac image, the microseismic locations can be used to tune the stimulation to cover just the intended reservoir depth interval without fracturing out of zone, understand the primary fracture orientation to optimize the well orientation, define the optimum spacing between stages and detect unexpected fracture growth such as fault activation. More fundamentally, however, microseismic images of complex fracture networks have also been instrumental in a significant paradigm change in the engineer’s concept of hydraulic fractures from simple, planar fractures to intersecting fractures in various directions. This paradigm shift proved planar hydraulic fracture modeling software, long the key tool in the stimulation engineer’s arsenal, obsolete and only now are complex fracture mechanics modeling tools being developed. In the interim, engineers sought a simple description of the hydraulic fracture effectiveness which gave rise to the volume of the microseismicity as a metric for the stimulated reservoir volume. Within specific formations the relative stimulated volume has been shown to correlate with the well production. In addition to the stimulated reservoir volume, the fracture density and spacing within that volume is also an important well performance factor, and can potentially be estimated using the density of the microseismic source strength deformation as a proxy for the relative fracture density. Nevertheless stimulated volume has become a favoured measure of the fracture effectiveness, despite the fact that microseismic accuracy and geomechanical stress activated deformation cause the hydraulically activated volume to be overestimated. More importantly, the microseismic volume is much larger than the effective volume: the portion of the hydraulic volume that contains proppant and remains open and permeable after the stimulation. Although some applications attempt to use the microseismic volume as a direct measure of the effective volume, the underlying assumptions are invalid and can potentially lead to misapplication of the microseismic data. However, the complex fracture models implicitly handle the mass balance of the total injection volume and the portion containing proppant, and once calibrated with the microseismic extents can be used to estimate the effective propped volume. While such calibrated model simulations are just now being pursued, the modeling shows promise to significantly improve the microseismic interpretation, with the added attraction of potentially included other microseismic source deformation attributes to further validate the modeled geomechanical deformation. However, before we can fully utilize the microseismic deformation, a rock physics model of the proportion of the strain captured through the microseismicity relative to the total geomechanical deformation must be defined. Another growing microseismic application is integrating the microseismic with geological reservoir models, commonly seismic reservoir characterization, which provides key insights into the geologic factors impacting hydraulic fracture variability. Insights into the impact of geologic heterogeneity can be used to design improved fracturing strategies and potentially better reservoir drainage and well sequencing by understanding geomechanical sweetspots in the reservoir which may be preferentially fractured.



About the Author(s)

Shawn Maxwell is Chief Geophysicist and Microseismic Advisor for Schlumberger, and is based in Calgary. Prior employment included initiating microseismic services with Pinnacle and ESG, and as a Lecturer at Keele University in England. Shawn was awarded a Ph.D. in earthquake seismology from Queen’s University. He serves on various microseismic focused committees and workshops around the globe, and is currently passive seismic associate editor for Geophysics.



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