A system and a method for producing an anisotropic velocity model. Vertical seismic profile (VSP) data is obtained for a geological area. At least two stiffness coefficients in a fourth-rank elasticity stiffness tensor are calculated based on p-wave and s-wave velocities determined using the VSP data. Microseismic profile data for the geological area is obtained and all remaining unknown stiffness coefficients in the fourth-rank elasticity stiffness tensor are calculated using the microseismic profile data.

A system includes a first instrumented bridge plug positionable in a downhole wellbore environment. The first instrumented bridge plug includes an acoustic source for transmitting an acoustic signal. The system also includes a second instrumented bridge plug positionable in the downhole wellbore environment. The second instrumented bridge plug includes an acoustic sensor for receiving a reflected acoustic signal originating from the acoustic signal. The reflected acoustic signal being usable to interpret wellbore formation characteristics of the downhole wellbore environment.

A system to obtain information about a subsurface formation, in some embodiments, comprises an array of acoustic transmitters in a first well; a distributed acoustic sensing (DAS) fiber in a second well; and processing logic, in communication with the array of acoustic transmitters and the DAS fiber, that activates the array of acoustic transmitters and the DAS fiber so as to use the Doppler effect to obtain information about the subsurface formation.

A system to obtain information about a subsurface formation, in some embodiments, comprises an array of acoustic transmitters in a first well; a distributed acoustic sensing (DAS) fiber in a second well; and processing logic, in communication with the array of acoustic transmitters and the DAS fiber, that activates the array of acoustic transmitters and the DAS fiber so as to use the Doppler effect to obtain information about the subsurface formation.

Methods and mediums for estimating stimulated reservoir volumes are disclosed. Some method embodiments may include obtaining microseismic event data acquired during a hydraulic fracturing treatment of the formation, the data including event location and at least one additional attribute for each microseismic event within the formation; filtering the microseismic events based on the at least one additional attribute; determining a density of filtered microseismic events; weighting the filtered microseismic events based on the density; and determining a stimulated reservoir volume estimate based on filtered and weighted microseismic events.

Methods and mediums for estimating stimulated reservoir volumes are disclosed. Some method embodiments may include obtaining microseismic event data acquired during a hydraulic fracturing treatment of the formation, the data including event location and at least one additional attribute for each microseismic event within the formation; filtering the microseismic events based on the at least one additional attribute; determining a density of filtered microseismic events; weighting the filtered microseismic events based on the density; and determining a stimulated reservoir volume estimate based on filtered and weighted microseismic events.

An example method includes at least partially positioning within a wellbore an optical fiber of a distributed acoustic sensing (DAS) data collection system. Seismic data from the DAS data collection system may be received. The seismic data may include seismic traces associated with a plurality of depths in the wellbore. A quality factor may be determined for each seismic trace. One or more seismic traces may be removed from the seismic data based, at least in part, on the determined quality factors.

An example method includes at least partially positioning within a wellbore an optical fiber of a distributed acoustic sensing (DAS) data collection system. Seismic data from the DAS data collection system may be received. The seismic data may include seismic traces associated with a plurality of depths in the wellbore. A quality factor may be determined for each seismic trace. One or more seismic traces may be removed from the seismic data based, at least in part, on the determined quality factors.

Uncertainty of microseismic monitoring results can be reduced to improve hydraulic fracture modeling. A computing device can use a fracture model to determine a predicted geometry of a hydraulic fracture in a subterranean formation based on properties of a fracturing fluid that is introduced into the subterranean formation. An uncertainty index of the predicted geometry of the hydraulic fracture can be determined based on an uncertainty value of the predicted geometry and a trend of uncertainty values. When the injection flow rate of the fracturing fluid is less than a maximum flow rate, it can be increased from an initial injection flow rate to an increased injection flow rate in response to determining the uncertainty index exceeds a pre-set maximum.

Uncertainty of microseismic monitoring results can be reduced to improve hydraulic fracture modeling. A computing device can use a fracture model to determine a predicted geometry of a hydraulic fracture in a subterranean formation based on properties of a fracturing fluid that is introduced into the subterranean formation. An uncertainty index of the predicted geometry of the hydraulic fracture can be determined based on an uncertainty value of the predicted geometry and a trend of uncertainty values. When the injection flow rate of the fracturing fluid is less than a maximum flow rate, it can be increased from an initial injection flow rate to an increased injection flow rate in response to determining the uncertainty index exceeds a pre-set maximum.