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.

A method and system for picking first-break times for a seismic dataset are disclosed. The method includes generating a pre-processed seismic dataset and an initial refraction velocity model from the pre-stack seismic dataset and generating a first-break energy-enhanced seismic dataset using nonlinear beamforming applied to the pre-processed seismic dataset and the initial refraction velocity model. The methods further include estimating a refined refraction velocity model from the first-break energy-enhanced seismic dataset, and generating a post-processed seismic dataset from the refined refraction velocity model and first-break energy-enhanced seismic dataset. The methods still further include, for each pre-stack trace, determining a first-break time from the post-processed seismic dataset and the refined refraction velocity model. The methods also include generating a seismic image based on the first-break time for each pre-stack trace and determining a location of a hydrocarbon reservoir based on the seismic image.

In an example implementation, first seismic energy is generated using first seismic sources positioned on an earth's surface. First data including measurements of the first seismic energy is obtained from first geophones positioned at a first depth below the earth's surface. Second data including measurements of the first seismic energy is obtained from second geophones positioned on the earth's surface. Second seismic energy is generated using second seismic sources positioned on an earth's surface and proximal to the second geophones. Third data including measurements of the second seismic energy is obtained from third geophones positioned at the first depth below the earth's surface. A propagation of the first seismic energy along a first path is estimated based on the first, second and third data. One or more characteristics of the target are determined based on the estimate.

The present disclosure provides novel systems and methods of locating downhole objects in a wellbore, the condition of casing within the wellbore, and characteristics of a subterranean formation. More specifically, data associated with a hydraulic impulse in fluid in the wellbore is used to determine a location of a downhole object. Data associated with the hydraulic impulse is collected and then processed in the frequency domain to identify the location of the downhole object. The downhole object may be a tool positioned within the wellbore or a fracture network that communicates with the wellbore by a perforation through wellbore casing. The system and method of the present disclosure can also be used to identify locations of unintended holes or perforations in casing and other tubulars. One aspect of the present disclosure is a system and method of locating a downhole object by analyzing pressure data from a hydraulic impulse transmitted through a fluid in a wellbore and that reflects off of the downhole object.

A method may include obtaining seismic data regarding a geological region of interest. The seismic data may include various pre-processed gathers. The method may further include obtaining a machine-learning model that is pre-trained to predict migrated seismic data. The method may further include selecting various training gathers based on a portion of the pre-processed gathers, a migration function, and a velocity model. The method may further include generating a trained model using the training gathers, the machine-learning model, and a machine-learning algorithm. The method may further include generating a seismic image of the geological region of interest using the trained model and a remaining portion of the seismic data.

A method for estimating a thickness of a deep reservoir may include obtaining seismic data relating to the deep reservoir. The method may include performing spectral decomposition to obtain one or more frequency components from the seismic data. The method may include identifying a number of mono-frequency horizons corresponding to high frequencies in the seismic data, determining whether the deep reservoir is a thin reservoir based on the number of mono-frequency horizons, and estimating the thickness of the deep reservoir when the deep reservoir is determined to be the thin reservoir.

A system is described for calibrating fiber optic well measurements including a fiber optic waveguide disposed proximal to a wellbore, a sensor coupled to the fiber optic waveguide, the sensor configured to record a plurality of signals detected by the waveguide, and a computer system configured to calibrate the signals from the waveguide by filtering out one or more background acoustic responses from the plurality of signals. A method for calibrating the signals is also described.

A seismic source includes a base plate having a bottom surface contacting a surface of the ground. The coupler is connectable to the bottom surface of the base plate and projects downward from the base plate. The coupler contain soil under the base plate during operation. Another seismic source includes a base plate and at least one contact member. The base plate has an upper surface engaging the seismic source, a lower surface configured to contact a soil surface. The contact member projects from the lower surface and has a planar bottom surface with a surface area less than a surface area of the base plate lower surface.

Various embodiments include apparatus and methods implemented to simulate geophone data from distributed acoustic sensing data, such as simulating vertical component geo phone 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 used 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.

A method can include receiving a first trained machine model trained via unsupervised learning using unlabeled seismic image data; receiving labeled seismic image data acquired via an interactive interpretation process; and building a second trained machine model, as initialized from the first trained machine model, via supervised learning using the received labels, where the second trained machine model predicts stratigraphy of a geologic region from seismic image data of the geologic region.