Systems and methods are disclosed for hydrocarbon exploration using seismic imaging and, more specifically, measuring randomness in seismic data utilizing a vectorized disorder algorithm. The vectorized disorder algorithm is configured to measure the randomness level (e.g., noise) in seismic data to improve seismic data processing/imaging and the ability to expose subsurface geology. The vectorized disorder algorithm includes performing convolution of seismic data with a vectorized disorder operator having an extra dimension than the seismic data. A nonlinear reduction operation is performed on the vectorized output to generate a randomness distribution dataset having the same dimension as the input data. The randomness distribution dataset comprises data points representing the level of randomness for respective seismic data points. A more accurate seismic image is generated from the seismic data as a function of the measured randomness distribution.

The present invention pertains to the fields of geology and geophysics, is designed for use for onshore seismic acquisition. The method involves distributing and arranging the elements used in the acquisition of two-dimensional seismic data from dynamite sources, enabling imaging quality to be improved. The use of sources of dynamite with single charges and variable weight at each shot point results in the generation of seismic waves with variable energy that provide reflections with complementary frequency and amplitudes content for use in the geophysical imaging of geological features. The stacking of this incremental content generated by charges of variable weights results in a significant improvement in the resolution of the processed seismic data on both the continuity of stratigraphic reflectors and existing geological framework.

A computer system receives a post-stack time-domain image having a first spectrum and representing one or more subsurface structures. The computer system reconstructs an increased-frequency version of the post-stack time-domain image using L0-constrained inversion and a least-squares mismatch ratio. The increased-frequency version of the post-stack time-domain image includes structural artifacts. The computer system removes the structural artifacts from the increased-frequency version of the post-stack time-domain image using singular value decomposition. The computer system combines the increased-frequency version of the post-stack time-domain image with the post-stack time-domain image using a weighting function. The computer system generates a combined version of the increased-frequency version of the post-stack time-domain image and the post-stack time-domain image. The combined version represents the one or more subsurface structures and has a second spectrum broader than the first spectrum.

Methods of oil and gas exploration that may include: obtaining wavefield data representing recordings from a propagating wavefield through a geophysical volume; obtaining at least one reference digital image of a portion or all of the geophysical volume generated from the recorded wavefield data, wherein the reference image may have a reference sampling ratio and a reference image quality value; selecting a holographic computational method of imaging the wavefield data; selecting a data subset from the wavefield data based on one or more parameters selected from the group consisting of field sampling, imaging sampling, and image quality; decimating the data subset, wherein the decimated data subset may represent a sampling ratio less than the reference sampling ratio; and generating a new digital image based on the selected holographic computational method of imaging, the data subset, and parameters corresponding to the data sub set.

A method includes receiving seismic data of a seismic survey; defining a two-dimensional domain in dimensions x and y; identifying a target trace (S, R) of the seismic survey where S represents a source at (x.sub.s, y.sub.s) and where R represents a receiver at (X.sub.R, y.sub.R); defining with respect to the two-dimensional domain, a source trace (S, X.sub.1) as a primary trace, a receiver trace (R, X.sub.2) as a primary trace, and a generator trace (X.sub.1, X.sub.2) as associated with an interbed multiple generator; convolving the primary traces and crosscorrelating with the generator trace for a plurality of different (X.sub.1, X.sub.2) pairs where each of the plurality of (X.sub.1, X.sub.2) pairs defines a line segment where the line segments are substantially parallel to one another; and, based at least in part on the convolving the primary traces and crosscorrelating with the generator trace, generating seismic data with attenuated multiple energy.

Survey design for data acquisition using marine non-impulsive sources can include operating a first marine non-impulsive source at over a first frequency range for a first sweep length and operating a second marine non-impulsive source over a second frequency range for a second sweep length. The first sweep length can be based on available geological information of a subsurface location that is a target of a marine seismic survey, an intended speed of a marine survey vessel, and the first frequency range. The second sweep length can be based on the available geological information, the intended speed, and the second frequency range.

Techniques are disclosed relating to performing marine surveys according to dither values generated based on one or more dithering constraints. This may include for example, determining a set of nominal shot points for a marine seismic energy source and determining dither values for ones of the nominal shot points. In some embodiments, the dither values are randomly generated, subject to a duplication constraint such that at most a threshold number of dither differences between consecutive shot points that fall within discrete ranges. In some embodiments, actual shot points are determined for the planned sail line based on application of the determined dither values to the nominal shot points. In various embodiments, the disclosed techniques may facilitate a separate de-blending procedure to separate signals from the marine seismic energy source and signals from one or more other seismic energy sources to be used for the seismic survey.

Methods of identifying a subterranean tunnel using digital imaging that may include: obtaining data of a propagating wavefield through a propagating volume that includes a portion of the earth's subsurface; obtaining a reference digital image of the propagating volume; selecting a holographic computational method of wavefield imaging; selecting a wavefield based on one or more parameters; calculating a sampling ratio by dividing a number of data samples in the data subset by a number of image samples in the data subset; decimating the data subset; generating a new digital image based on the selected holographic computational method of imaging, the decimated data subset, and parameters corresponding to the data subset; determining a quantitative difference measure between the reference digital image and the new digital image, and image quality; and identifying the subterranean tunnel.

Methods and apparatuses for processing seismic data acquired with multicomponent sensors build an accurate S-wave velocity model of a surveyed underground formation using a full waveform inversion (FWI) approach. PS synthetic data is generated using approximative acoustic equations in anisotropic media with a P-wave model, a current S-wave velocity model and a reflectivity model as inputs. The current S-wave velocity model is updated using FWI to minimize an amplitude-discrepancy-mitigating cost function that alleviates the amplitude mismatch between the PS observed data and the PS synthetic data due to the use of the approximative acoustic equations.

Land seismic survey including providing at least two vibrators in a first group, wherein each vibrator in the first group is assigned to a respective source line, where the source lines of the first group run substantially parallel to one another; providing at least two vibrators in a second group, wherein each vibrator in the second group is assigned to a respective source line that is different than the source lines assigned to vibrators from the first group; actuating the vibrators in the first group simultaneously using different frequency bandwidth sweeps and different phase encodings; actuating the vibrators in the second group at the same time as those in the first group, and simultaneously using different frequency bandwidth sweeps and different phase encodings; and detecting the resulting seismic signals with a plurality of seismic sensors that are placed in contact with the earth and as part of a seismic spread.