Microseismic monitoring has become an accepted industry practice to determine fracture geometry such as height, length, and azimuth. Recent advances in microseismic monitoring have allowed additional rock characteristics to be determined. One such characteristic, the source mechanism, can now be identified with high confidence in many cases. A source mechanism reveals the type and orientation of mechanical failure of the rock under pressure, providing the dip, strike, and rake angles of movement. Understanding the failure mode corresponding to different source mechanisms better characterizes reservoir geology and subsurface structure and identifies possible complex fracture trend orientations. Not only does this have significant applicability today for fracture mapping, but it also may prove to be useful in reservoir monitoring applications of microseismic by detecting reservoir changes over time. In theory, detecting a shift in source mechanism patterns over time may lead to a better understanding of preferential production flows in many kinds of reservoirs, similar to traditional 4-D seismic.
Understanding source mechanisms
A source mechanism is a characterization of the instantaneous deformation of the rock that defines a microseismic event. Hydraulic fracture stimulation can induce both tensile and shear failure. Tensile failure usually occurs when new fractures form. Shear deformation is most often associated with reactivation of existing fractures and faults. Figure 1 shows three categories of a rock’s response to stress: reverse dip-slip, normal dip-slip, and strike-slip. A large-aperture, wide-azimuth (WAZ), and high-fold seismic monitoring array is required to distinguish specific mechanism types and orientations.
Detecting source mechanisms using microseismic monitoring
There are two mature microseismic monitoring acquisition technologies offered in today’s market: surface and downhole. Downhole monitoring, developed first, uses a string of geophones lowered into a nearby monitoring or observation well. Downhole monitoring is a good way to evaluate hydraulic fracturing results when the monitoring well is drilled near the target formation depth and positioned within 500 m (1,600 ft) of the well that is undergoing treatment.
But the array acquisition geometry from a single monitoring well does not allow for source mechanism inversion. The limited spatial sampling inherent in a single downhole array results in a low probability of capturing the sense of motion and amplitude of first arrivals that define the orientation of source mechanism nodal planes. Multiple monitoring wells, appropriately positioned to provide sufficient sampling of azimuth and aperture, can capture enough information to distinguish source mechanisms. These, however, can be cost-prohibitive and logistically complex. As a result, multiwell downhole monitoring is a relatively rare practice.
The surface microseismic monitoring approach, introduced and improved over the last decade, is now available through a number of vendors. Surface monitoring is the more reliable approach for detecting source mechanisms. (For the purpose of this discussion, “surface approach” also includes shallow subsurface geophones buried to depths of 100 m [300 ft].) The large-aperture, high-fold WAZ sampling provided by a properly designed surface monitoring program is able to detect the difference in first ground motion arrivals throughout the array. Proper processing of the data reveals source mechanism dip, strike, and rake angles for sufficient signal quality events.
Results in the Marcellus
The Marcellus shale in the Appalachian basin is located across significant portions of New York, Pennsylvania, Ohio, and West Virginia. The Marcellus shale is characterized by two prevailing regional joint sets. The J1 joint set was formed during the tectonic stresses associated with the Alleghenian orogeny. A change in the direction of the maximum horizontal stress (SHmax) during the late Alleghenian orogeny led to the formation of the younger J2 joint set. The two joints are usually perpendicular within the basin and are associated with increased pore pressures from hydrocarbon generation. J1 joints are generally parallel to SHmax in this region, so it can be difficult to determine whether hydraulic fracturing activity is inducing new fractures in the rock or stimulating the preexisting J1 fractures.
Two microseismic failure types were detected in the Marcellus study: dip-slip and strike-slip. Figure 2 provides a view of all microseismic events generated during the hydraulic fracturing treatment. When viewed in time-lapse, it is clear that the dip-slip source mechanisms are more frequent at the beginning of the treatment, indicating that the maximum stress axis is vertical. The J1 joint set is being reactivated at the onset of treatment. At the end of the stimulation, strike-slip events increase, illustrating that the maximum stress has shifted toward the horizontal and resulting in the reactivation of the J2 joint set in addition to the J1 joint set.
When a hydraulic fracture initiates and grows in the direction of SHmax, it can expand with increased pressure. As the stimulated J1 joints in the Marcellus expand, the horizontal stress increases, eventually becoming greater than the vertical stress. As the J1 joints open up, fracture interactions lead to strike-slip failure on J2 joints. The result, as shown in Figure 3, is reactivation on both existing natural fracture planes, thus increasing hydrocarbon flow to the wellbore via the fracture network. The applicability of source mechanism analysis in this study demonstrates the value of microseismic monitoring beyond traditional information used for well spacing purposes.
For more in-depth exploration of source mechanism analysis in the Marcellus, see SPE 163826, “Integrated Microseismic Monitoring for Field Optimization in the Marcellus Shale – A Case Study.”