A method includes receiving, via a processor, input data based upon received seismic data, migrating, via the processor, the input data via a pre-stack depth migration technique to generate migrated input data, encoding, via the processor, the input data via an encoding function as a migration attribute to generate encoded input data having a migration function that is non-monotonic versus an attribute related to the input data, migrating, via the processor, the encoded input data via the pre-stack depth migration technique to generate migrated encoded input data, and generating an estimated common image gather based upon the migrated input data and the migrated encoded input data. The method also includes generating a seismic image utilizing the estimated common image gather, wherein the seismic image represents hydrocarbons in a subsurface region of the Earth or subsurface drilling hazards.

An acoustic logging tool may comprise a center load carrying pipe, a receiver module connected to the center load carrying pipe, one or more transmitter modules connected to the center load carrying pipe, and one or more mass modules connected to the center load carrying pipe.

This disclosure describes a system and method for generating images and location data of a subsurface object using existing infrastructure as a source. Many infrastructure objects (e.g., pipes, cables, conduits, wells, foundation structures) are constructed of rigid materials and have a known shape and location. Additionally these infrastructure objects can have exposed portions that are above or near the surface and readily accessible. A signal generator can be affixed to the exposed portion of the infrastructure object, which induces acoustic energy, or vibrations in the object. The object with affixed signal generator can then be used as a source in performing a subsurface imaging of subsurface objects, which are not exposed.

The method acquiring a ground seismic dataset over a region of interest by defining a geometry of acquisition of the seismic dataset specifying a location of a plurality of seismic sources and a location of a plurality of seismic receivers, inducing a seismic signal with at least one first seismic source of the plurality of seismic sources, and measuring the corresponding ground vibrations induced by the at least one first seismic source with the plurality of seismic receivers to obtain a first seismic dataset. Then processing the first seismic dataset and modifying the geometry of acquisition of the first seismic dataset by specifying a location of at least an additional seismic source and/or a location of at least an additional seismic receiver, based on analyzing the processed first seismic dataset.

A seismic system that includes a seismic source configured to generate a first seismic signal and a second seismic signal in a formation adjacent the seismic source. A first downhole sensing device disposed in a first borehole configured to detect the first seismic signal and the second seismic signal in the formation; and a first surface acquisition system is in communication with the first downhole sensing device. The first surface acquisition system is configured to: determine a first reference transit time based at least in part on detection of the first seismic signal by the first downhole sensing device; a first subsequent transit time based at least in part on detection of the second seismic signal by the first downhole sensing device; and whether a synchronization variation is expected to be present based at least in part on the first reference transit time and the first subsequent transit time.

A procedure that integrates petrophysics and rock typing taken from vertical well measurements, 3D seismic elastic properties and seismic attributes, and geostatistical modeling to build a 3D reservoir model is provided. The 3D reservoir model may be directly incorporated into horizontal fracture model designs. The developed 3D reservoir model for a subsurface volume may be used in a fracture model to optimize fracturing designs and maximize well performance.

A method to process vertical seismic profile (VSP) data includes receiving VSP data, migrating the VSP data output using an initial velocity model to produce migrated depth values associated with the respective receivers, sorting and collecting the migrated depth values corresponding to each receiver to produce a migrated common receiver gather (CRG) associated with each receiver, stacking the migrated depth values of the CRGs corresponding to respective fixed lateral positions in an image volume to produce a common image gather (CIG) associated with each lateral position, and generating a semblance panel having the stacked depth migration values plotted as contours on a first axis for velocity ratio (vr), which is based on migration velocity and true velocity) and a second axis for true depth (Zt). The method further includes updating the initial velocity model based on a plurality of data points selected from the semblance panel to provide an updated velocity model.

Methods for measuring seismic velocities and for monitoring local changes in inter-well seismic velocities in real time are described. Two or more spaced-apart observation wells are provided. Seismic receiver arrays are placed in the observation wells, and a seismic source array is provided at surface locations away from the well bores and producing areas. Compression (P), vertical shear (Sv) and/or horizontal shear (Sh) seismic wave signals are generated from each element of the seismic source array, and the seismic signals arriving at the receivers in the observation wells are recorded. The virtual source method in seismic interferometry technology is then applied to the recorded data to compute emulated cross-well seismic signals of the virtual sources at receiver locations in one observation well propagating toward the receivers at other observation wells. Analysis of direct arrivals in emulated cross-well seismic signals between the two wells can be subsequently completed to out extract travel times and inter-well seismic velocities and rock properties.

One embodiment includes receiving seismic data from a plurality of seismic sensors located proximate to a build section of a wellbore that is drilled into a subsurface. The seismic data is recorded for a plurality of seismic waves, at different angles, sent from a plurality of seismic sources towards the plurality of seismic sensors. Locations of the plurality of seismic sources relative to locations of the plurality of seismic sensors are such that the plurality of seismic waves are essentially planar at the plurality of seismic sensors. The subsurface is essentially homogenous proximate to the build section. For at least a portion of the plurality of seismic waves, the embodiment includes determining a slowness vector for each seismic wave, and determining a phase velocity and a phase angle. The embodiment includes determining at least one anisotropic parameter value for the build section, determining a vertical velocity value, and using these.

A method for applying separated wave-field imaging onshore (1) by artificially creating up-going and down-going fields and (2) by using these fields in a migration algorithm. If there are any surface multiples in the data, the resulting image created using the migration algorithm will be distorted by the unknown free-surface reflection coefficient. In fact, the surface multiples may be generated with a complex series of reflection coefficients. The distortions found in the resulting image created using the migration algorithm are then removed.