**1. Introduction**

Microseismic monitoring has become a valuable tool for optimizing stimulations, comple‐ tions, and overall field development, particularly in unconventional reservoirs. This technology was initially rooted in geothermal energy [1,2], but subsequently was used for many years in research projects to understand fracturing in unconventional reservoirs, such as in the Multiwell Experiment [3,4], the M-Site fracture diagnostics laboratory [5-8], the Carthage Cotton Valley fracturing test [9,10], and for other processes, such as drill cuttings injection [11]. It finally reached a level of sophistication and reliability to function as a service technology in the early 21st century [12,13], and many thousands of hydraulic fractures have been monitored since that time. In addition to providing a "window" into the subsurface for fracture optimization and control, the large amount of microseismic data that has been gathered provides a significant database that can be used for environmen‐ tal surety.

Microseismicity occurs because of geomechanical changes to the reservoir as a result of the fracturing process [14,15], and detection and location of these "events" provides a methodol‐ ogy to monitor fracture growth patterns and overall dimensions. One of the curious features of microseismic technology is that no one has ever seen the slippage plane of a microseism that was induced by a hydraulic fracture. As a result, the understanding of microseismicity has been through a down-scaling of earthquake seismology [16], examination of fracture behav‐ iour in minebacks [17,18], comparisons with rock bursts and laboratory acoustic emissions [19,20], and geomechanics considerations of the way in which hydraulic fractures perturb a reservoir [21].

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Nevertheless, there have been several validation experiments where other measurement technologies have been used to verify the accuracy and interpretation of microseismicity, and these have been very helpful in promoting an understanding of the process of microseismic activation during a fracturing treatment. The most comprehensive of these tests was the M-Site test funded by GRI and DOE; it was developed as a fracture diagnostics laboratory in the Piceance basin of Colorado [5-8]. Intersection wells, downhole tiltmeters, tracers, pressure interference, and other technologies were used to show the accuracy of determining the fracture azimuth, length, and height by these methods in typical sandstone reservoir rocks. In these tests, it became clear that microseismicity does not necessarily occur on the hydraulic fracture, but can develop along planes of weakness at an offset distance that depends on both the formation and the treatment.

While there have been no published tests about fracturing in shale reservoirs that provide the full detail available from M-Site, the project described by Fisher et al. [12] in the Barnett shale has many of the same elements as M-Site. Both downhole and surface tiltmeters were used to supplement the microseismic data, and numerous offset producing wells were used to monitor the movement of fracturing fluid during the treatment. Wells that were "bashed" (i.e., loaded up with fracturing fluids) provided direct evidence of actual fluid presence at that location that could be compared to the microseismicity. This comprehensive test verified the actual formation of a "network" in this reservoir.

With a reasonable level of accuracy and interpretability established by validation tests, such as those described, microseismicity can be used for field development, completion design, stimulation optimization, and addressing environmental concerns. The last aspect, with respect to aquifers and seismicity, is very important for current unconventional reservoir development throughout the world.
