Methods and systems for determining a property of a tubular are described. Measurement data of cross-sectional shapes of the tubular at a plurality of depth positions is provided. A three-dimensional mesh representing the tubular based on the cross-sectional shapes is generated. A stress simulation using the three-dimensional mesh to provide an integrity assessment of the tubular is performed.

Systems and methods of detecting marine seismic survey parameters are provided. A data processing system can obtain seismic data from seismic data acquisition units disposed on a seabed responsive to an acoustic signal propagated from an acoustic source through a water column. The data processing system can determine from the seismic data, a direct arrival time for the acoustic signal at each of the plurality of seismic data acquisition units, and can obtain an estimated depth value of each of the plurality of seismic data acquisition units and an estimated water column transit velocity of the acoustic signal. The data processing system can apply a depth model and a water column transit velocity model to the estimated depth value and to the estimated water column transit velocity determine an updated depth value and an updated water column transit velocity for each of the plurality of seismic data acquisition units.

Techniques for estimating and visually presenting formation slowness are disclosed herein. The techniques include receiving acoustic signal responses from adjacent formations at a plurality of depths in a borehole environment, mapping a distribution of the acoustic signal responses at each depth according to slowness and a frequency values, determining at least one confidence interval to define a coherence threshold for the distribution of the acoustic signal responses at each depth, generating a variable density log for each depth based on the distribution of acoustic signals responses that satisfy the confidence interval for one or more frequency ranges, determining a formation slowness value for each depth based on the variable density log for the each depth, and presenting a semblance map that includes a slowness axis, a depth axis, the formation slowness value for each depth, and at least a portion of the distribution of acoustic signal responses at each depth.

A seismic dataset and a task to be performed with the seismic dataset may be received. A representative seismic line representative of the seismic dataset may be generated. The representative seismic line may include pixel data representative of the seismic dataset. Based on the representative seismic line, the task may be performed. The task may include at least finding an analogous geological region by searching for an analogous seismic dataset existing in a seismic database by comparing the representative seismic line with the analogous seismic dataset's representative seismic line.

Systems and methods of the present disclosure are directed to adjustment of seismic survey boundaries to remove or minimize data gaps, thereby providing optimized seismic interpretation.

Methods and systems for displaying sonic logging data are described herein. The displayed data includes highly reliable quality control (QC) indicators that can be used to identify any need for a dispersion correction. The disclosed data-driven approach determines whether a dispersion curve is asymptotic to the true formation shear slowness by calculating a coherence of the slowness at frequency intervals of the dispersion curve to indicate the level of the velocity dispersion. This coherence indicator can then be plotted against the averaged slowness within the frequency interval to show how well the asymptotic slowness is approached. The coherence indicator can be projected onto a slowness log as a QC indicator. A calculated formation shear slowness can be overlaid upon the slowness log.

A method is described for seismic imaging that may include receiving digital seismic data; processing the digital seismic data to create a digital seismic image in a seismic domain; flattening the digital seismic image to generate a digital flattened image; identifying artifacts in the digital flattened image; transforming the artifacts back into the seismic domain; and reprocessing the digital seismic data based on the artifacts in the seismic domain to generate a digital image with reduced artifacts. The method may be executed by a computer system.

The disclosure relates to methods and systems for analyzing an image of the formation intersected by a borehole. One of the methods determines a local apparent dip of the borehole at least at a measured depth i represented on the image, applies at least a window to the image, wherein each of the windows includes one of the measured depth i and is shaped as a function of the determined local dip at the corresponding measured depth i, compares a texture of at least a first zone of each window and a texture of at least a second zone of said window, wherein each of the first and second zones are adjacent and shaped as a function of the determined dip. Based on the comparison, the method determines at least a location of a texture boundary and derives a property of the formation. The other method includes determine locations of the texture boundaries, segmenting the image as a function of the texture boundaries, and perform clustering of the segments in order to determine a facies of the formation.

Systems and methods for visualizing attributes of multiple fault surfaces in real time by calculating the attributes as each respective fault surface is picked.

A method for processing vertical seismic profiling (VSP) data is provided. The method includes receiving VSP data in response to seismic energy applied to the formation, processing a down-going portion of the VSP data associated with a down-going wave field, outputting a first set of estimation values based on processing the down-going portion of the VSP data, the first set of estimation values estimating at least one of slowness or velocity, processing an up-going portion of the VSP data associated with an up-going wave field, outputting a second set of estimation values based on processing the up-going portion of the VSP data, the second set of estimation values estimating at least one of slowness or velocity, and determining an estimation associated with the formation based on the first and second sets of estimation values.