The accuracy of microseismic monitoring is highly dependent on the quality of the velocity structure used in the analysis of the arrival time or waveform data. Because most rocks associated with hydrocarbon reservoirs are generally anisotropic, methods must be developed to circumvent the effects of anisotropy or to determine the anisotropy parameters for appropriate inclusion. Some field measurements of horizontal vs. vertical velocities are given to help assess the degree of transverse anisotropy. Synthetic case studies are also provided to show how various monitoring strategies and velocity models can affect the accuracy of the microseismic locations.


Microseismic monitoring is a valuable tool for both hydraulic fracture and reservoir monitoring. Although the primary application is currently hydraulic fracture mapping, it also has great promise for monitoring other injection and production processes, particularly for cases such as steam injection, drill cuttings injection, and CO2 sequestration in which it is important to ensure that the injected material is placed in a controlled manner.

This technology is a straightforward application of earthquake seismology (Albright 1982) in which compressional (P) and shear (S) arrivals are detected at some number of receivers and the location of the microseism is deduced by means of ray tracing or other travel-time estimates through some known velocity structure. The uncertainty associated with the microseismic location has two primary components. The first is the ability to accurately detect the P and S arrivals at a sufficient number of receivers and to determine the polarization characteristics of those phases; the second is to adequately characterize the velocity structure so that the inferred location is reasonably accurate.

The first issue has many implications relative to monitor-well distance, number of receivers, sampling rate, aperture design, receiver coupling, vector fidelity, noise, and other similar issues (Warpinski et al. 1998). These are important elements of any microseismic test, but are not considered in this paper. This work focuses on the determination of an acceptably accurate velocity structure.

Formation sonic velocities are routinely measured in wellbores by using various sonic logging tools, many of which can determine both the compressional and shear velocities. However, these logging tools routinely obtain the velocity along the axis of the borehole, which is the vertical velocity in most wells in which they are commonly run. Most sedimentary rocks exhibit a significant degree of transverse anisotropy (Thomsen 1986) in their velocities as a result of layering, mineralogy, and natural fracturing. As a result, the vertical velocities that are routinely obtained with wellbore sonic logs are inappropriate for use in microseismic mapping; the direct use of these velocities can result in large errors in the location of the microseisms.

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