MicroSeismic Inc.

United States

MicroSeismic Inc.

United States
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Patent
MicroSeismic Inc. | Date: 2016-10-13

A method for passive seismic imaging includes entering into a programmable computer seismic signals measured at a plurality of spaced apart locations above a volume of Earths subsurface to be evaluated. The signals are measured at each location along different directions to enable resolution of motion in three orthogonal directions. A seismic moment tensor is determined for at least one seismic event occurring in the subsurface from the measured seismic signals. Divergence-free transverse) and curl-free longitudinal components of a source term are determined from the moment tensor, seismic velocities, and the measured seismic signals. An image is generated at at least one point in the subsurface using the determined components.


A method for determining hypocenters of microseismic events includes entering as input to a computer seismic signals recorded by a plurality of seismic sensors disposed proximate a volume of subsurface to be evaluated. For each point in space in the volume, and for a plurality of preselected origin times, a seismic energy arrival time at each seismic sensor is determined. Event amplitudes for each arrival time are determined. A synthetic event amplitude is calculated for each arrival time. A semblance between the determined event amplitudes and the synthetic event amplitudes is determined. Existence of an actual microseismic is determined event when the semblance exceeds a selected threshold.


A method for determining spatial distribution of proppant incudes using signals detected by seismic sensors disposed proximate a formation treated by pumping fracturing fluid containing the proppant. Origin time and spatial position of seismic events induced by pumping the fracturing fluid are determined. Volume and orientation of at least one fracture in the subsurface formation associated with each induced seismic event are determined. Spatial distribution of a volume of the pumped fracturing fluid is determined using the volume and orientation of each fracture. A length of ellipsoidal axes is selected using a surface defined by a selected fractional amount of the total volume of frac fluid pumped into the formation. Spatial distribution of the proppant is determined using proppant mass, specific gravity and expected proppant porosity in the fractures, and spatially distributing a volume of the fractures within an ellipsoid defined by the ellipsoidal axes.


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.


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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