Abstract: 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.

Abstract: A distributed acoustic sensing (DAS) system is coupled to an optical fiber along a plurality of channels. The system generates a DAS seismic profile of the subsurface formation based on detected seismic data, identifies at least one region having coherent noise, and identifies which of the plurality of channels are within the identified at least one region. For each trace of data associated with the plurality of noisy channels, the system converts, from a time to a wavelet domain, the trace of data and a reference trace having less coherent noise, and suppresses the wavelet coefficients of the trace of data based on the wavelet coefficients of the reference trace. After the system mitigates the noise in the wavelet domain, an inverse wavelet transform is applied to the trace of data to convert back to the time domain and create a reduced noise DAS seismic profile.

Abstract: A distributed acoustic sensor is positioned within a wellbore of a geologic formation. Seismic waves are detected using the distributed acoustic sensor. A raw seismic profile is generated based on the detected seismic waves. Resonant noise is identified and reduced in seismic data associated with the raw seismic profile.

Abstract: High fidelity velocity models are generated for acoustic vertically transverse isotropic media by taking advantage of full-waveform based modeling using VSP data. The present disclosure determines VTI parameters in acoustic media using pseudo-acoustic equations which can eliminate the contribution from shear waves, and thus significantly reduce the time needed to perform inversion. The methods disclosed herein provide workflows for performing full waveform inversion to provide velocity models used to generate seismic images with high quality and resolution.

Abstract: Various embodiments include apparatus and methods implemented to simulate geophone data from distributed acoustic sensing data, such as simulating vertical component geophone waveform data from distributed acoustic sensing data. Embodiments include measuring vertical component of strain at a plurality of vertical positions along an optical fiber disposed along a wellbore at a well site. The measured vertical component of strain can be processed to generate a vertical component of displacement. The vertical component of displacement can be generated to generate a vertical component of velocity from which a waveform simulating a waveform of geophone data can be output. Additional apparatus, systems, and methods are disclosed.

Abstract: A sensing system may comprise a deployment device having an optical fiber cable with a predetermined curvature or an intrinsic curvature. The sensing system may be deployed into a location that is remote or difficult to navigate, for example, a large vessel or a borehole of a well. A deployment device may deploy the optical fiber cable and a tension control tool may maintain the deployment device along with the optical fiber cable in a straight or non-curved shape until the optical fiber cable has reached a predetermined location or position. A force may then be applied to the optical fiber cable to cause a portion of the optical fiber cable to contact an interior wall of the area or location, for example, a borehole or the deployment device. Measurements may be retrieved from the optical fiber cable, for example, measurements used in distributed acoustic sensing in vertical seismic profiling.

Abstract: Various embodiments include apparatus and methods implemented to take into consideration gauge length in optical measurements. In an embodiment, systems and methods are implemented to interrogate an optical fiber disposed in a wellbore, where the optical fiber is subjected to seismic waves, and to generate a seismic wavefield free of gauge length effect and/or to generate a prediction of a seismic wavefield of arbitrary gauge length, based on attenuation factors of a plurality of wavefields acquired from interrogating the optical fiber. In an embodiment, systems and methods are implemented to interrogate an optical fiber disposed in a wellbore, where the optical fiber is subjected to seismic waves, and to convert a seismic wavefield associated with a first gauge length to a seismic wavefield associated with a different gauge length that is a multiple of the first gauge length. Additional apparatus, systems, and methods are disclosed.

Abstract: 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.

Abstract: A method of performing acoustic logging comprises generating a first acoustic signal from a first source at a first time, wherein the first source is a first distance away from a wellbore wall, and generating a second acoustic signal from a second source at a second time, wherein the second source is a second distance away from the wellbore wall. The difference between the first time and the second time depends on a calibration value.

Abstract: An example system for noise removal in distributed acoustic sensing data may include a distributed acoustic sensing (DAS) data collection system and an information handling system coupled thereto. The information handling system may receive seismic information from the DAS data collection system. The seismic information may include seismic traces associated with a plurality of depths in the wellbore. The information handling system may also generate a noise pilot trace by stacking one or more of the seismic traces, and subtract the noise pilot trace from the seismic information received from the DAS data collection system.

Abstract: Tools and methods for monitoring a subterranean formation is provided. Methods for monitoring include: creating a time-lapse azimuth stack between an azimuth stack on a first seismic survey and an azimuth stack on a second seismic survey; identifying a lowest root mean square energy and a highest root mean square energy for each time-lapse azimuth stack; and recording an azimuth with largest overall root mean square energy.

Abstract: Embodiments of the subject technology provide for predicting seismic impedance. The subject technology generates a corridor stack based on vertical seismic profile (VSP) data of a wellbore in a subterranean formation. The subject technology generates an initial estimate of a velocity model for the subterranean formation below the wellbore. The subject technology generating a density model for the subterranean formation below the wellbore based on information from nearby wells. The subject technology inverts, based on a global inversion algorithm and the initial estimate of the velocity model, the generated corridor stack to determine a set of velocity models. The subject technology generates impedance models in a depth domain based on the generated density model and the set of velocity models. Further, the subject technology stores the generated impedance models.

Abstract: A method for processing distributed acoustic sensing (DAS) vertical seismic profiling (VSP) data is provided. The method includes operations to receive DAS data associated with an optical fiber's response to seismic energy applied by three seismic energy sources. The three seismic energy sources each configured to apply seismic energy to the optical fiber in a direction that is orthogonal to a direction of seismic energy applied by the other two seismic energy sources, the optical fiber is at least partially positioned within a wellbore, and the DAS data includes three components directed in an axial direction of the wellbore associated with energy application by the respective three seismic energy sources. The method further includes operations to apply reciprocity to the three components to model an equivalent vertical point force source in the wellbore with receivers configured to receive the three components at a location of the respective three seismic energy sources.

Abstract: Embodiments of the subject technology provide for predicting seismic impedance. The subject technology generates a corridor stack based on vertical seismic profile (VSP) data of a wellbore in a subterranean formation. The subject technology generates an initial estimate of a velocity model for the subterranean formation below the wellbore. The subject technology generating a density model for the subterranean formation below the wellbore based on information from nearby wells. The subject technology inverts, based on a global inversion algorithm and the initial estimate of the velocity model, the generated corridor stack to determine a set of velocity models. The subject technology generates impedance models in a depth domain based on the generated density model and the set of velocity models. Further, the subject technology stores the generated impedance models.

Abstract: In accordance with embodiments of the present disclosure, systems and methods for downsampling DAS data in a way that enables accurate interpretation of acoustic events occurring in the data are provided. Such methods may be particularly useful when interpreting large sets of data, such as DAS VSP data collected during hydrocarbon recovery operations. The methods generally involve identifying data channels affected by noise from a DAS data set, and then interpolating from the surrounding data. This may improve the quality of the resulting downsampled data, with respect to the signal to noise ratio, compared to what would have occurred by merely decimating unwanted data channels. In addition, a priori information about channel fading, the desired downsampling rate, and the slowest expected elastic waves may be used to filter the DAS data. This may achieve a higher signal-to-noise ratio in the downsampled data.

Abstract: A method for processing distributed acoustic sensing (DAS) vertical seismic profiling (VSP) data is provided. The method includes operations to receive DAS data associated with an optical fiber's response to seismic energy applied by three seismic energy sources. The three seismic energy sources each configured to apply seismic energy to the optical fiber in a direction that is orthogonal to a direction of seismic energy applied by the other two seismic energy sources, the optical fiber is at least partially positioned within a wellbore, and the DAS data includes three components directed in an axial direction of the wellbore associated with energy application by the respective three seismic energy sources. The method further includes operations to apply reciprocity to the three components to model an equivalent vertical point force source in the wellbore with receivers configured to receive the three components at a location of the respective three seismic energy sources.

Abstract: A sensing system may comprise a deployment device having an optical fiber cable with a predetermined curvature or an intrinsic curvature. The sensing system may be deployed into a location that is remote or difficult to navigate, for example, a large vessel or a borehole of a well. A deployment device may deploy the optical fiber cable and a tension control tool may maintain the deployment device along with the optical fiber cable in a straight or non-curved shape until the optical fiber cable has reached a predetermined location or position. A force may then be applied to the optical fiber cable to cause a portion of the optical fiber cable to contact an interior wall of the area or location, for example, a borehole or the deployment device. Measurements may be retrieved from the optical fiber cable, for example, measurements used in distributed acoustic sensing in vertical seismic profiling.

Abstract: A method of performing acoustic logging comprises generating a first acoustic signal from a first source at a first time, wherein the first source is a first distance away from a wellbore wall, and generating a second acoustic signal from a second source at a second time, wherein the second source is a second distance away from the wellbore wall. The difference between the first time and the second time depends on a calibration value.

Abstract: In some embodiments, an apparatus and a system, as well as a method and an article, may operate to generate a parent population, wherein each member of the parent population includes a set of model parameters describing a layer model of the geological formation; to execute a perturbation algorithm to generate subsequent child populations, from the parent population, until a termination criterion is met; to provide a plurality of solutions based on at least one member of the parent population and on at least one member of each child population; and to control a drilling operation based on a revised layer model that has been generated based on a selected one of the plurality of solutions. Additional apparatus, systems, and methods are disclosed.

Abstract: Geophysical prospecting may be achieved using borehole seismic data and processing velocity seismic profiles using downward continuation to simulate the seismic source being at the depth of the borehole receivers. Such methods may involve collecting seismic data for a subterranean formation with at least one borehole receiver; grouping the seismic data into a one common receiver gather corresponding to each borehole receiver; performing a downward continuation on at least one of the common receiver gathers to produce corresponding downward continued common receiver gathers; performing a normal moveout analysis on at least one of the downward continued common receiver gathers to produce corresponding semblance velocity spectra; and analyzing at least one of the semblance velocity spectra for a zone of interest in the subterranean formation.