Hydraulic fracturing is an essential technology for hydrocarbon extraction from both conventional and unconventional reservoirs. Recently, concern has developed regarding induced seismicity generated in association with multistage fracturing of horizontal wells in shale reservoirs. A review of thousands of fracture treatments that have been microseismically monitored shows that the induced seismicity associated with hydraulic fracturing is very small and not a problem under any normal circumstances. Results are presented for six major shale basins in North America.

Summary Hydraulic fracturing is an essential technology for hydrocarbon extraction from both conventional and unconventional reservoirs. Recently, concern has developed regarding induced seismicity generated in association with multistage fracturing of horizontal wells in shale reservoirs. Microseismic monitoring of hydraulic fractures, which has been a routine service for over a decade, can provide information about the levels of seismic activity commonly found during fracturing. A review of thousands of fracture treatments that have been microseismically monitored shows that the induced seismicity associated with hydraulic fracturing is very small and not a problem under any normal circumstances. Results are presented for six major shale basins in North America in which hundreds to thousands of fracture treatments have been conducted in predominatly gas reservoirs. This paper reviews the methodology, the data, and the interpretation of the microseismicity.

Microseismic monitoring has become an important part of borehole completions in tight-reservoir formations. Usually, clear objectives for a microseismic survey are set prior to the data acquisition. The possibility of meeting these objectives is determined by the acquisition geometry, the target formation, the completion schedule, and only to a lesser extent, by the data quality itself. Provided is a tutorial on the content and use of prejob modeling and design studies as a tool to anticipate viewing distances, data quantity, location accuracy, event magnitudes, achievable mapping distances, expected waveforms, and noise levels. In addition, potential challenges in meeting the survey objectives can be identified and solutions to these challenges can be devised prior to the survey. For downhole surveys, this involves the evaluation of different sensor array geometries and their impact on the location accuracy in different parts of the expected model. The sensitivity of the event location on the velocity model can be estimated using an initial log-based model. Recently, the detailed characterization of the event mechanism in form of a moment tensor inversion has received increased attention. The accuracy of the inverted moment tensor depends largely on the coverage of the focal sphere, i.e., the distribution of the sensors around the event location. Based on the sensor positions, areas with high- and low-quality moment tensor inversion results can be identified prior to data acquisition through the distribution of the condition number. Depending on the survey objectives and the given constraints, the microseismic design study might show that the survey objectives cannot be met. In this case, it is possible to evaluate alternate technologies, e.g., distributed temperature sensing (DTS), ahead of the project for their potential to meet these challenges.

Along with horizontal drilling and hydraulic fracturing technology, monitoring-induced microseismic activity during hydraulic fracturing has played a significant role in the economic development of today's prolific tight-gas and shale resource plays. Many microseismic fracture monitoring papers in the current literature discuss the equipment, how to acquire and process microseismic data, and how to determine an appropriate velocity model. Unfortunately, for an operating company's completion engineers and geophysicists charged with interpreting these data and integrating them with other data sets, only a few papers discuss the impact of artifacts and location uncertainties on the interpretation. While microseismic data have been very useful in the economic development of resource plays, there are a number of significant pitfalls and interpretational issues that, if not understood, will potentially lead to erroneous interpretations. This is especially important for any real-time decisions during a hydraulic fracture treatment.

Stimulated reservoir volumes (SRV) calculated from microseismic-event distributions have been successfully used to establish correlations with the production for tight-oil and -gas reservoirs. Although only applicable in reservoirs where complex fracture networks are created, the calculation of SRV numbers has proven to be a valuable measure of the stimulation effectiveness and, in some circumstances, prediction of the well's production. It is important to note that, while SRV is an important baseline measurement of the total rock volume affected by the stimulation, other factors, such as the density and conductivity of fractures within the SRV, are just as important for well performance. Calculating SRV from microseismic-event distributions often involves "shrink-wrapping" the event locations without any consideration of the location uncertainty of the individual event. Not just the amount of location uncertainty, but the directionality of the nonuniform uncertainty space as well as its definition impact the calculated SRV number. Other impacts are the radiation pattern, viewing distance, and accuracy of the underlying velocity model. In this paper, the quantitative impact of these factors on the SRV number is discussed and the developed methodology is applied to several datasets, resulting in the calculation of uncertainty bars for the SRV number. These SRV uncertainty ranges help explain some of the anomalous deviations of the SRV number in individual projects from the general trend in a certain area, which is demonstrated using an example from the Barnett shale.