A method for obtaining zero-offset and near zero offset seismic data from a marine survey, with separation of direct arrival information and reflectivity information, the method including: modeling a direct arrival estimate at a passive near-field hydrophone array by using a notional source separation on active near-field hydrophone data; generating reflection data for the passive near-field hydrophone array by subtraction of the modeled direct wave from data recorded by the passive near-field hydrophone array; generating near zero-offset reflectivity traces by stacking the reflection data for the passive near-field hydrophone array on a string-by-string basis or on a combination of strings basis; generating reflectivity information at the active near-field hydrophone array by subtracting the direct arrival estimate modeled using the notional source separation from the active near-field hydrophone data; and generating an estimate of zero-offset reflectivity traces by calculating a cross-correlation between the between the reflectivity information at the active near-field hydrophone array and the near zero-offset traces and performing an optimized stacking with summation weights based on coefficients of the cross-correlation.

A method including selecting a forward model based on a modeled well structure and including a single modeled acoustic source located in a modeled wellbore and a plurality of modeled acoustic sensors located in a modeled source area, simulating an acoustic signal generated by the single modeled acoustic source and received by each modeled acoustic sensor, calculating phases of the simulated acoustic signals received at each modeled acoustic sensor, obtaining with a principle of reciprocity a plurality of modeled acoustic sources in the modeled source area and a single modeled acoustic sensor in the modeled wellbore, calculating phase delays of the simulated acoustic signals between each modeled acoustic source and the single modeled acoustic sensor, detecting acoustic signals generated by a flow of fluid using acoustic sensors in a wellbore, and processing the acoustic signals using the phase delays to generate a flow likelihood map.

A method for estimating a fluid pressure required to stimulate a subsurface formation includes using seismic signals detected by a plurality of seismic sensors disposed proximate the subsurface formation. Spatial positions and times of origin (“hypocenters”) of each of a plurality of microseismic events induced by pumping fluid into the subsurface formation are estimated. Magnitudes and directions of principal stresses are estimated from the hypocenters and from amplitude and phase of the detected seismic signals for each of the microseismic events. Shear and normal stresses of induced fractures are from the estimated principal stresses. A fluid pressure required to cause formation failure on each fracture is estimated using the estimated shear and normal stresses.

The invention comprises a method for mapping a volume of the Earth's subsurface encompassing a selected path within said volume, comprising dividing the volume of the Earth's subsurface into a three-dimensional grid of voxels and transforming detected seismic signals representing seismic energy originating from said volume of the Earth's 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 Earth's subsurface to said selected path.

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.

The application describes methods and apparatus for seismic monitoring using fiber optic distributed acoustic sensing (DAS). The method involves interrogating a first optical fiber (102) deployed in an area of interest to provide a distributed acoustic sensor comprising a plurality of longitudinal sensing portions of fiber and also monitoring at least one geophone (107) deployed in the area of interest. The signal from the at least one geophone is analyzed to detect an event of interest (105). If an event of interest is detected the data from the distributed acoustic sensor acquired during said event of interest is recorded. The geophone may be co-located with part of the sensing fiber and in some embodiments may be integrated (307) with the sensing fiber.

A system includes a first wellbore operation controller for controlling a wellbore operation and generating a first broadcast indicating a first data topic desired for controlling the wellbore operation. The system also includes a second wellbore operation controller for generating a data stream associated with a wellbore and for generating a second broadcast indicating a second data topic that promotes the data stream. The system includes a mediator computing device that receives the first broadcast and the second broadcast and determines that the first wellbore operation controller is subscribed to the data stream by comparing the first data topic to the second data topic. In response to determining that the first wellbore operation controller is subscribed to the data stream, the mediator computing device creates a data link between the first wellbore operation controller and the second wellbore operation controller.

A method for determining maximum horizontal stress in a subsurface formation includes using recordings of seismic energy detected proximate the subsurface formation to determine hypocenters of microseismic events. A focal mechanism for each microseismic event is determined. A measurement corresponding to vertical stress magnitude at a depth of the subsurface formation is used to normalize horizontal stress magnitudes for formation depth. The focal mechanism is used to determine a maximum horizontal stress direction. A measurement corresponding to a depth normalized minimum horizontal stress magnitude and the focal mechanism are used to determine a depth normalized maximum horizontal stress magnitude.

A fracturing treatment optimization system using multi-point pressure sensitive fiber optic cables to measure interwell fluid interaction data, microdeformation strain data, microseismic data, distributed temperature data, distributed acoustic data, and distributed strain data from multiple locations along a wellbore. The fracturing treatment optimization system may analyze the interwell fluid interaction data, microdeformation strain data, microseismic data, distributed temperature data, distributed acoustic data, and distributed strain data, modify a subsurface fracture network model, and calculate interwell fluid interaction effects. The fracturing treatment optimization system may use the fracture network model to measure current and predict future fracture growth, hydraulic pressure, poroelastic pressure, strain, stress, and related completion effects. The fracturing treatment optimization system may enable real-time monitoring and analysis of treatment and monitoring wells. The fracturing treatment optimization system may suggest and effect modifications to optimize treatment of the treatment and monitoring wells.

A computer-implemented method for seismic event localization includes: generating, with at least one processor, a vectorized snapshot matrix representing wave propagation data at a series of snapshots in time for a subterranean formation; computing a reduced orthonormal column basis matrix based on the vectorized snapshot matrix; constructing a reduced order wave propagation model based on the reduced orthonormal column basis matrix; receiving seismic data collected from a plurality of receivers at the subterranean formation; generating a time-domain coefficient matrix based on back propagation of the received seismic data and the reduced order wave propagation model; reconstructing time-reversed wavefield data based on the time-domain coefficient vector; and generating signals for outputting wavefield or seismic event location information based on the time-reversed wavefield data.