Locating Microseismic Events and Determining Spatial Uncertainty Using 1C DAS Fiber Optic Strain Measurements or a Combination of 1C (DAS) and 3C (Geophones)

Abstract

In typical downhole-acquired microseismic monitoring surveys, three-component (3C) sensor arrays are generally wireline conveyed, offering between five to around one hundred sensors often evenly spaced over a specific interval. Those 3C sensors are point receivers that typically measure particle velocity or acceleration. On the other hand, fiber-optic based acquisition uses the entire length of the fiber cable as a series of 1C sensors to measure the finite strain along the fiber. This allows the user to have great control over the interval for strain measurement, known as the gauge length. Conventional downhole microseismic processing requires compressional (P) and shear (S) wave arrival times along with polarization to constrain microseismic event location (hypocenter) in 3D. Since 1C sensors provide no polarization information, Distributed Acousting Sensing (DAS)–geophone hybrid systems can be considered for deployment; thus, combining the strength of each individual system (i) 3C of downhole sensors for accurate hypocenter determination and (ii) large array aperture of the sensitive fiber. A migrationbased method is a practical option to estimate hypocenters. We implement a migration-based approach for the 1C-DAS – 3C-geophone hybrid system to determine hypocenters without time-picks. Such a hybrid system minimizes event location uncertainty thanks to the long aperture of the fiber array and the polarization information provided by the geophones. In our synthetic as well as real field case studies, we observe a reduction in event location uncertainty when combining both acquisition methods vs. when relying on a traditional 3C-geophone array only. In some cases, 3C sensors are not an option and only 1C sensors can be deployed. For such configurations, we quantify the uncertainty of microseismic event location using a DAS-only system with synthetic microseismic data taking information availability and varying well configurations into account. Depth of event and distance from the well are sufficiently constrained even with a single monitoring well. While azimuth uncertainty is reduced in the dual-well configuration compared to single well, independent azimuthal information is still required to locate the microseismic event in the 3D space. This condition is also true when monitoring from a lateral well. 3D event location can be achieved using three monitoring wells without any constraints. If only downhole wells are used, one needs to consider three vertical wells or one vertical well and one lateral well to best minimize location uncertainty. Otherwise, assumptions need to be made, particularly in relation to the azimuth of events from the well.