An information processing system having a processor and a memory device coupled to the processor, wherein the memory device includes a set of instruction that, when executed by the processor, cause the processor to receive a multi-dimensional grid of acoustic or elastic impedances determined from seismic survey data associated with a subterranean formation, receive elastic property data that describes elastic property characteristics used to sort pseudo-components, and wherein the respective pseudo-components are formed of a combination of two or more lithologies. The instructions, when executed by the processor, further cause the processor to define select design variables using the impedance arrays, perform optimization operations for optimizing select design variables by applying the elastic property data as a part of a constitutive relation, and output a distribution of the pseudo-components to characterize volumetric concentrations of spatially grouped lithologies in a control volume of the subterranean formation.

A system and a method for performing a borehole operation, wherein the system may comprise a coiled tubing string and a fiber optic cable disposed in the coiled tubing string and wherein the fiber optic cable is strain-coupled to the coiled tubing string. A method of performing a borehole operation may comprise disposing a coiled tubing string into a borehole and wherein a fiber optic cable is strain-coupled to the coiled tubing string, and measuring at least one property of the borehole with the fiber optic cable.

Disclosed are methods, systems, and computer-readable medium to perform operations including: receiving seismic data acquired by at least one receiver of a geologic survey system configured to perform a geologic survey of a subterranean formation, wherein the seismic data is associated with reflected acoustic signals generated by at least one source of the geologic survey system; calculating a ground force signal by stacking the acoustic signals generated by the least one source; calculating, using the ground force signal, a time and depth variant quality factor (Q) of the subterranean formation; and compensating, based on the time and depth variant Q, attenuation in the seismic data.

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.

The disclosure relates generally to the inversion of geophysical and/or logging measurements for formation evaluation and monitoring. The disclosure may be related to methods of deconvolution and/or inversion of piecewise formation properties. A method for formation evaluation from a downhole tool may comprise disposing a downhole tool into a wellbore, broadcasting a signal into a formation penetrated by the wellbore, recording the signal from the formation with at least one receiver disposed on the downhole tool, computing an objective function, and determining formation properties by minimizing the objective function.

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.

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 imaging one or more dipping structures is provided. The method comprises providing a given velocity model, calculating travel time of a seismic wave using the velocity model, estimating coherency of event signals of array data that are time-corrected for a trial reflector, weighting a waveform sample corresponding to the travel time based on the coherency, and mapping the weighted waveform sample.

A method can include receiving information associated with an interface between a first medium and a second medium where the information includes sensor data; based on at least a portion of the information, estimating wave properties that include elastic properties, depth-dependent properties and horizontal slowness; and, based on the estimated wave properties, calculating an orientation of a sensor utilized to acquire at least a portion of the sensor data.

Wavelet estimation may be performed in a reservoir simulation model that is constrained by seismic inversion data and well logs. A synthetic seismic trace is generated along with an estimated wavelet. The reservoir simulation model is revised based on results from model comparisons to actual data or base seismic data and is then used to perform a wavelet estimation. The estimated wavelet may then be used to plan further production at the well site environment, additional production at additional well site environments or any other production and drilling operation for any given present or future well site environment.