Since its inception in the 1970s and its commercialization circa 2000, microseismic monitoring has proved to be an invaluable tool for understanding underground processes. While its most common and notable use has been hydraulic-fracture mapping, it also is used for reservoir monitoring of thermal processes, drill-cuttings injection, geothermal hot-dry- rock stimulations, reservoir surveillance, and many other processes in oil and gas and mining.
Fig. 1 shows a typical layout for a monitoring test, with the offset monitoring well at some reasonable distance from the fracture (inset) and a receiver array somewhere near the depth of the fracture treatment. Because the amplitude of the microseism decays with distance, there is a maximum monitoring distance that can be used in any test with respect to both horizontal and vertical positioning. Designed correctly, this type of monitoring can provide information on fracture height, length, azimuth, asymmetry, dip, and complexity, which can be used to optimize the fracture design and field development.
To most outsiders, the entire process of microseismic monitoring appears to be something of an art, and the “what,” “why,” and “how” details are not very clear even though there have probably been more than 6,000 fracture treatments monitored since 2000, in rocks ranging from tight sandstones and gas shales to carbonates and even volcanic, and at depths ranging from several hundred feet to more than 13,000 ft. The purpose of this article is to lay out a basic framework for planning, executing, analyzing, and interpreting a microseismic mapping project and, hopefully, add some rigor to the process that can be used for guidelines or standards.