This disclosure presents systems, methods, and apparatus for determining cluster efficiency during hydraulic fracturing, the method comprising: measuring acoustic vibrations in fracking fluid in a fracking wellhead, circulating fluid line, or standpipe of a well; converting the acoustic vibrations into an electrical signal in a time domain; recording the electrical signal to memory; analyzing the electrical signal in the time domain for a window of time and identifying two amplitude peaks corresponding to a fracture initiation; measuring a time between the two amplitude peaks; dividing the time by two to give a result; multiplying the result by a speed of sound in the fracking fluid to give a distance between the fracture initiation and a plug at an end of a current fracking stage of the well; and returning a location of the fracture initiation to an operator based on the distance between the fracture initiation and the plug.

A method of determining a shear-wave attenuated vertical component vertical seismic profile (VSP) dataset is disclosed. The method includes, obtaining a multi-component VSP dataset, including a vertical and a horizontal component, transforming the vertical component into a vertical spectrum and the horizontal component into a horizontal spectrum, and designing a band-pass filter based, at least in part, on an energetic signal of the horizontal spectrum. The method further includes determining a muted vertical amplitude spectrum by applying the pass-band filter to an amplitude spectrum of the vertical spectrum, determining an estimated noise model based on the muted vertical amplitude spectrum and the vertical spectrum; and determining the shear-wave attenuated vertical component VSP dataset by adaptively subtracting the estimated noise model from the vertical component of the multi-component VSP dataset. A system including a seismic source, a plurality of seismic receivers, and a seismic processor for executing the method is disclosed.

Seismic data is processed using a full-waveform inversion using a model with a pseudo-δ layer. The presence of the pseudo-δ layer in the model enables handing the difference at the water bottom between acoustically generated synthetic data and seismic data that corresponds to an elastic medium. The pseudo-δ layer may be less than 100 m thick and/or may be located directly underneath the water bottom. The pseudo-δ layer may have a negative value for S and a null value for ϵ (δ and ϵ being Thomsen's anisotropy parameters).

This disclosure presents a system, method, and apparatus for classifying fracture quantity and quality of fracturing operation activities during hydraulic fracturing operations, the system comprising: a sensor coupled to a fracking wellhead, circulating fluid line, or standpipe of a well and configured to convert acoustic vibrations infracking fluid in the fracking wellhead into an electrical signal; a memory configured to store the electrical signal; a converter configured to access the electrical signal from the memory and convert the electrical signal in a window of time into a current frequency domain spectrum; a machine-learning system configured to classify the current frequency domain spectrum, the machine-learning system having been trained on previous frequency domain spectra measured during previous hydraulic fracturing operations and previously classified by the machine-learning system; and a user interface configured to return a classification of the current frequency domain spectrum to an operator of the fracking wellhead.

A seismic warning system comprises: a plurality of sensors, each sensor sensitive to a physical phenomenon associated with seismic events and operative to output an electronic signal representative of the sensed physical phenomenon; a data acquisition unit communicatively coupled to receive the electronic signal from each of the plurality of sensors, the data acquisition unit comprising a processor configured to estimate characteristics of a seismic event based on the electronic signal associated with a P-wave from each of the plurality of sensors; and a local device communicatively coupled to the data acquisition unit.

A seismic observation device includes: a waveform acquisition unit that acquires waveform data for a predetermined period including an observation start time of a P wave; a delay time specifying unit that inputs the waveform data to a trained model and acquires, from the trained model, a delay time from the observation start time of the P wave to an observation start time of an S wave; and an observation time estimation unit that estimates the observation start time of the S wave based on the observation start time of the P wave and the delay time.

Disclosed are acoustic logging systems and methods that involve correlating broadband acoustic signals acquired by a plurality of acoustic sensors at multiple depths within a wellbore to compute covariance matrices and their eigenvalues in the frequency domain for a plurality of frequency bins. In accordance with various embodiments, acoustic sources are detected and located based on the eigenvalues viewed as a function of depth and frequency.

A well system includes a fiber optic cable positionable downhole along a length of a wellbore. The well system also includes a reflectometer communicatively coupleable to the fiber optic cable. The reflectometer injects optical signals into the fiber optic cable and receives reflected optical signals from the fiber optic cable. Further, the reflectometer identifies strain detected in the reflected optical signals generated from seismic waves of a microseismic event. Additionally, the reflectometer identifies a focal mechanism of the microseismic event and velocities of the seismic waves. The reflectometer also determines a position of the microseismic event using the strain detected in the reflected optical signals, the focal mechanism of the microseismic event, and the velocities of the seismic waves.

Some aspects of what is described here relate to seismic profiling techniques. A seismic excitation is generated in a first directional section of a first wellbore in a subterranean region. Seismic responses associated with the seismic excitation are detected in directional sections of a plurality of other wellbores in the subterranean region. A fracture treatment of the subterranean region is analyzed based on the seismic responses. In some instances, a multi-dimensional seismic velocity model of the subterranean region is generated based on the seismic responses.

A method for identifying a location of a distributed acoustic system channel in a distributed acoustic system. The method may comprise generating a two or three dimensional layer model interface with an information handling system, preparing a P-wave first arrival pick time table, estimating an initial model layer properties, estimating a location of the distributed acoustic system channels, preparing an overburden file of layer properties, running an anisotropic ray tracing, defining an upper and a lower limits for model parameters, specifying parameters for the inversion, running an inversion, selecting a solution based at least in part on stored error predictions, and calculating a mean and a standard deviation of an inverted model parameter.