A method for determining a thermal maturity image of a subterranean region and a non-transitory computer readable medium, storing instructions for executing the method, are disclosed. The method includes, obtaining a seismic dataset for the subterranean region of interest, obtaining a thermal maturity value for a plurality of core samples taken from different positions within the subterranean region, and obtaining a plurality of well log types from the core sampling location. The method further includes determining a calibrated rock physics model based on the plurality of well log types, determining a pore fluid type based on the calibrated rock physics model, and determining a thermal maturity model based on the plurality of core samples, on the pore fluid type, and on the plurality of well logs. The method still further includes determining the thermal maturity image of the subterranean region based on the seismic dataset and thermal maturity model.

Disclosed herein are system, apparatus, article of manufacture, method and/or computer program product embodiments, and/or combinations and sub-combinations thereof, for using direction-angles to identify geologic features and geologic attributes for use in geothermal, oil and gas, mining, and other applications. An example embodiment operates by receiving a discrete three-dimensional (3D) representation of a geologic volume comprising a set of 3D orientations, where each 3D orientation is represented as a set of direction-angles measured relative to a set of coordinate axes. The example embodiment further operates by receiving a set of other measurements of properties of the geologic volume, In response, the example embodiment operates by correlating the set of 3D orientations with the set of other measurements to generate a geologic correlation data structure. Subsequently, the example embodiment operates by identifying a geologic attribute or a geologic feature associated with the geologic volume based on the geologic correlation data structure.

A DAS VSP technique is used to determine the induced fracture height and fracture density of an induced fracture region. The DAS VSP technique obtains pre-hydraulic fracturing DAS VSP survey time-lapse data to establish a baseline reference for the direct acoustic wave travel time. The DAS VSP technique obtains one or more time-lapse data corresponding to the subsequent monitor surveys conducted after each hydraulic fracturing stage along the well. Forward modeling is used to determine a theoretical acoustic wave travel time difference. The forward modeling uses seismic anisotropy to describe the behavior of seismic waves traveling through the induced fracture regions. An inversion scheme is then used to invert for the induced fracture height and the fracture density using the forward modeling. The two extracted induced fracture characteristics may then be used to determine optimal hydraulic fracturing parameters.

A method can include accessing a trained machine model as trained to analyze digital seismic data of a region with respect to a structural feature of a geologic region; analyzing at least a portion of the digital seismic data using the trained machine model to generate results; and outputting the results as indicators of spatial locations of the structural feature of the geologic region.

Methods and systems, including computer programs encoded on a computer storage medium can be used for identifying primary-wave (P-wave) and secondary-wave (S-wave) characteristics of an underground formation by separating P-wave and S-wave modes of seismic data generated by applying a seismic source to a subterranean region of a geological area. Particle motion vectors of a P-wave are parallel to a propagation vector of the P-wave, whereas particle motion vectors of an S-wave are perpendicular to a propagation vector of the S-wave. The parallel and perpendicular relationship between the motion and propagation vectors of the respective P- and S-waves provide a basis for separating P- and S-wave components from a wavefield. The separation methodology extracts P-wave components and S-wave components from the wavefield based on an estimated angle between propagation vectors and wave motion vectors for the wavefield.

The present invention belongs to the field of treatment for data identification and recording carriers, and specifically relates to a method and system for evaluating the filling characteristics of a deep paleokarst reservoir through well-to-seismic integration, which aims to solve the problems that by adopting the existing petroleum exploration technology, the reservoir with fast lateral change cannot be predicted, and the development characteristics of a carbonate cave type reservoir in a large-scale complex basin cannot be identified. The method comprises: acquiring data of standardized logging curves; obtaining a high-precision 3D seismic amplitude data body by mixed-phase wavelet estimation and maximum posteriori deconvolution and enhancing diffusion filtering. According to the method and the system, the effect of identifying the development characteristics of the carbonate karst cave type reservoir in the large-scale complex basin can be achieved, and the characterization precision is improved.

The present disclosure belongs to the technical field of seismic exploration imaging, and relates to an interpretive-guided velocity modeling seismic imaging method and system, a medium and a device. The method comprises the following steps: S1. performing first imaging on a given initial velocity model to obtain a first imaging result; S2. performing relative wave impedance inversion on the first imaging result to obtain a relative wave impedance profile; S3. performing Curvelet filtering on the relative wave impedance profile to obtain a first interpretation scheme; S4. superposing the first interpretation scheme and the initial velocity model to obtain a new migration velocity field; S5. performing second imaging on a new migration velocity field to obtain a second imaging result; and S6. repeating steps S2-S4 for the obtained second imaging result until a final seismic imaging result is obtained.

A method for generating an image of a subsurface based on blended seismic data includes receiving the blended seismic data, which is recorded so that plural traces have uncontaminated parts with different uncontaminated recording time lengths, selecting plural subgroups (SG1, SG2) of traces so that each subgroup (SG1) includes only uncontaminated parts that have a same uncontaminated recording time length, processing the traces from each subgroup to generate processed traces, mapping the processed traces to a same sampling, combining the processed traces from the plural subgroups (SG1, SG2) to generate combined processed traces, and generating an image of a structure of the subsurface based on the combined processed traces.

A method may include obtaining fracture image data regarding a geological region of interest. The method may further include determining various fractures in the fracture image data using a first artificial neural network and a pixel-searching process. The method may further include determining a fracture model using the fractures, a second artificial neural network, and borehole image data. The method may further include determining various fracture permeability values using the fracture model and a third artificial neural network. The method may further include determining various matrix permeability values for the geological region of interest using core sample data. The method may further include generating a coarsened grid model for the geological region of interest using a fourth artificial neural network, the matrix permeability values, and the fracture permeability values.

The present disclosure relates to a method for determination of a real subsoil geological formation. In at least one embodiment, the method includes receiving a model representing the real subsoil, determining a first fluvial geological formation in said model using parametric surfaces, determining a subsequent fluvial geological formation as a deformation of the first fluvial geological formation using parametric surfaces, and subtracting the first fluvial geological formation from the subsequent fluvial geological formation to create a new geological formation named point bar formation.