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Disclosed herein are various embodiments of methods and systems for providing a graphical skeletonization representation of fractures and faults in a subsurface of the earth. According to some embodiments, as fracturing fluid is pumped into a target geologic formation through a well bore, and as the formation fractures or faults in response to the fracturing fluid being pumped under high pressure therein, seismic wavefronts are generated at points of fracture related to movement of a fluid pressure wave induced by fracturing or other fluids moving through the formation, or the extraction of fluids such as gas and/or oil from the formation, which are detected by surface and/or downhole sensors. Data corresponding to signals generated by the surface and/or downhole sensors are recorded and subsequently analyzed to determine in near real-time the locations of the fractures or faults using skeletonization data processing techniques and methods.


A method for imaging microseismic events includes determining a hypocenter of microseismic events generated by at least one stage of a hydraulic fracturing procedure from recorded signals detected by seismic sensors disposed above a wellbore in the subsurface. Spatial position of the microseismic events occurring sequentially in the fracturing procedure is determined with reference to a center of fracturing procedure. Each microseismic event is assigned to one of a plurality of selected size bins defined positionally with reference to the center of the fracturing procedure. A property of each microseismic event assigned to each bin is aggregated and an image of the aggregated property is generated with respect to position referenced to the center of the fracturing procedure.


A method for estimating uncertainties in determining hypocenters of seismic events occurring in subsurface formations according to one aspect includes determining estimates of event locations by choosing local peaks in summed amplitude of seismic energy detected by an array of sensors disposed above an area of the subsurface to be evaluated. For each peak, the following is performed: recomputing the summed amplitude response for a selected set of points of comprising small perturbations in time and space from the estimated event locations; computing second derivatives of log likelihood function from the stacked responses at the estimated location and the perturbed locations; assembling the second derivatives into a Fisher information matrix; computing an inverse of the Fisher information matrix; determining variances of estimated parameters from the elements from the diagonal of the inverted matrix; and computing standard deviations of the estimated parameters by calculating a square root of the variances.


Patent
MicroSeismic Inc. | Date: 2014-06-05

The invention comprises a method for mapping a volume of the Earths subsurface encompassing a selected path within said volume, comprising dividing the volume of the Earths subsurface into a three-dimensional grid of voxels and transforming detected seismic signals representing seismic energy originating from said volume of the Earths subsurface when no induced fracturing activity is occurring along said selected path and conducted to a recording unit for recording into signals representing energy originating from the voxels included in said grid of voxels, and utilizing said transformed seismic signals to estimate spatially continuous flow paths for reservoir fluids through said volume of the Earths subsurface to said selected path.


A method for determining fracture plane orientation from seismic signals detected above a subsurface formation of interest includes detecting seismic signals using an array of seismic sensors deployed above the subsurface formation during pumping of a hydraulic fracture treatment of the subsurface formation. A time of origin and a spatial position of origin (hypocenter) of microseismic events resulting from the hydraulic fracture treatment are determined. Time consecutively occurring ones of the hypocenters falling within a selected temporal sampling window are selected. A best fit line through the selected hypocenters using a preselected linear regression coefficient is determined. The selecting hypocenters and determining best fit lines is repeated for a selected number of windows.


Patent
MicroSeismic Inc. | Date: 2014-02-10

A method for estimating moment magnitude of a seismic event occurring in subsurface formations includes measuring seismic signals at each of a plurality of seismic sensors disposed in a selected pattern proximate a subsurface area in which the seismic event occurs. Amplitude events corresponding to the seismic event from the signals detected by each receiver are time aligned. Corrections are applied to the aligned events for density, for the formation velocity, for the radiation pattern, for propagation effects and instrument response. The corrected events are summed. Seismic moment is determined from the summed, corrected events. A moment magnitude is estimated from the seismic moment.


Patent
MicroSeismic Inc. | Date: 2011-11-22

Disclosed are various embodiments of methods for determining the velocity of seismic energy in geologic layers using Seismic Emission Tomography (SET) imaging of drill bit noise, by recording microseismic data during a drilling operation, recording the time and the position of a drill bit in a well bore during the drilling operation, processing the microseismic data using SET software to image microseismic events proximate a known time and position of the drill bit using an estimated velocity model, computing the difference between the known time and position of the drill bit and the time and position of the microseismic event determined from the SET data, varying the estimated velocity model to minimize the difference between the known time and position of the drill bit and the time and time and position of the microseismic event determined from the SET data.


Disclosed are various embodiments of methods for identifying faults and fractures, and other permeable features, within geologic layers during a drilling operation comprising; recording microseismic data during a drilling operation; recording times and positions of a drill bit in a well bore during the drilling operation; processing microseismic data at a plurality of selected times and locations to image microseismic events and identifying faults and fractures, and other permeable features, from corresponding images of microseismic events. In other embodiments, the integrity of a cementing operation may be verified by recording microseismic data during a cementing operation; recording times and positions of a cementing operation in a well bore during the cementing operation; processing microseismic data at a plurality of selected times and locations to image microseismic events and identifying faults and fractures, and other permeable features, within the cemented zone from corresponding images of microseismic events.


A method for determining a stimulated rock volume includes determining a position of a plurality of seismic events from seismic signals recorded in response to pumping fracturing fluid into a formation penetrated by a wellbore. The signals generated by recording output of a plurality of seismic receivers disposed proximate a volume of the Earths subsurface to be evaluated. A source mechanism of each seismic event is determined and is used to determine a fracture volume and orientation of a fracture associated with each seismic event. A volume of each fracture, beginning with fractures closest to a wellbore in which the fracturing fluid was pumped is subtracted from a total volume of proppant pumped with the fracture fluid until all proppant volume is associated with fractures. A stimulated rock volume is determined from the total volume of fractures associated with the volume of proppant pumped.


A method for determining a volume of a fracture network includes detecting seismic signals deployed over an area of the subsurface during pumping of fracturing fluid into at least one wellbore drilled through the area. A hypocenter of each fracture induced by the pumping is determined using the seismic signals. A facture network and associated fracture volume is determined using the determined hypocenters and seismic moments determined from the detected seismic signals. A maximum value of a scaling factor is determined based on a subset of the hypocenters having a highest cumulative seismic moments. The scaling factor is determined by relating a pumped volume of the fracturing fluid with respect to the determined fracture volume. Dimensions of each fracture are scaled using the maximum value of the scaling factor. The fracture volumes are recalculated using the scaled dimensions.

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