Techniques are disclosed relating to reducing noise in geophysical marine survey data. Such techniques may include adapting an initial set of noise templates to recorded seismic data to generate adapted noise templates and estimating a noise component in the recorded seismic data. The estimating may include determining a degree to which noise and signal components are correlated in the recorded seismic data and masking the recorded seismic data proportionally to the degree of correlation. The adapted noise templates may then be further adapted to a difference between the estimate of the noise component and the noise templates themselves. Resultant noise templates may then be applied to denoise the recorded seismic data.

Techniques are disclosed relating to reducing noise in geophysical marine survey data. Such techniques may include adapting an initial set of noise templates to recorded seismic data to generate adapted noise templates and estimating a noise component in the recorded seismic data. The estimating may include determining a degree to which noise and signal components are correlated in the recorded seismic data and masking the recorded seismic data proportionally to the degree of correlation. The adapted noise templates may then be further adapted to a difference between the estimate of the noise component and the noise templates themselves. Resultant noise templates may then be applied to denoise the recorded seismic data.

A wavefield simulation method for extending the explicit finite-difference stability condition comprises: performing a time-step iteration on the basis of a wave-field numerical simulation model and adopting the spatial filtering method to filter out wave-field components appearing in the high wave number region (S1); when all time-step iterations end, saving wave-field data that obtained from the time iterations (S2); performing the inverse time-dispersion transform on the target wave-field data required to be output from the wave-field data, so as to obtain the wave-field data with time-dispersion removed (S3); and saving the wave-field data after the inverse time-dispersion transform processing (S4). Further provided are an electronic apparatus and a computer-readable storage medium used to implement the wave-field simulation method for extending the explicit finite-difference stability conditions.

A wavefield simulation method for extending the explicit finite-difference stability condition comprises: performing a time-step iteration on the basis of a wave-field numerical simulation model and adopting the spatial filtering method to filter out wave-field components appearing in the high wave number region (S1); when all time-step iterations end, saving wave-field data that obtained from the time iterations (S2); performing the inverse time-dispersion transform on the target wave-field data required to be output from the wave-field data, so as to obtain the wave-field data with time-dispersion removed (S3); and saving the wave-field data after the inverse time-dispersion transform processing (S4). Further provided are an electronic apparatus and a computer-readable storage medium used to implement the wave-field simulation method for extending the explicit finite-difference stability conditions.

Automatic propagation of real-world parent seismic images to efficiently generate a collection of realistic synthetic child training images to train a model for accurate automatic seismic interpretation. A 3D structural model in a present-day geological space (e.g., G.sub.B) depicting subsurface locations of particles (e.g., in region B) may be transformed by a 3D coordinate space transformation (e.g., uvt.sub.B) to a depositional space (e.g., G*.sub.B) depicting past depositional locations of those particles (e.g., corresponding depositional region B). A real-world parent image depicting subsurface locations of particles (e.g., in region A) may be transformed, via a forward transformation (e.g., uvt.sub.A), to a depositional seismic image in the depositional space of the three-dimensional structural model (e.g., G*.sub.A=G*.sub.B). A reverse transformation (e.g., uut.sub.B.sup.−1) may transform the depositional seismic image from the depositional space into synthetic child training images in the present-day geological space (e.g., G.sub.B) for training the model.

The invention describes a procedure for determining the shale brittleness index from data obtained in the well by at least three well-logging tools measuring corresponding parameters. Three tools, namely sonic, density and deep resistivity, are selected. The time interval signals from the sonic tool are converted to the P-wave velocity. The product of signals obtained from the sonic and density tools (P-wave velocity×Bulk density=Acoustic impedance (AI)) responds in the same direction to a variation of the volume of water and organic matter (OM) volume of the rocks, whereas the third tool (Deep Resistivity) reacts very differently in response to a change of one or other of these same components, in a three-pole diagram, with rock matrix, OM and water as the three components onto an Acoustic Impedance vs resistivity ratio function plane. The resistivity ratio function is the square root of the ratio between the water resistivity and the measured formation resistivity. The position of the curved matrix-water line with OM=0 fraction by volume is fixed connecting the rock matrix point with that of the water point. The slope of the matrix-water curve is controlled by the tortuosity factor ‘a’ that is selected for a formation zone considering the pore structure, grain size and level of compaction. The data points to be analysed can be calibrated accordingly by iterating the resistivity of water (Rw) and occasionally the tortuosity factor (a) parameter to obtain the Rw value. In a graph where the parameters used depend, for example, on the sonic velocity in the rock, the rock bulk density and on the electric resistivity of the formations, the iso quartz/calcite-content lines are denoted as iso-brittleness line as with an increase in quartz/calcite content, both organic content and porosity decrease, resulting in an increase in brittleness. These iso-brittleness lines form a set of parallel curved lines intersecting the matrix-water reference curved line. Brittleness is derived from that graph corresponding to each pair of values of the parameters measured in the well.

The invention describes a procedure for determining the subsurface total organic content (TOC) from data obtained in the well by at least three well-logging tools measuring corresponding parameters. Three tools, namely sonic, density and deep resistivity are selected. The time interval signals from the sonic tool are converted to the P-wave velocity. The product of signals obtained from the sonic and density tools (P-wave velocity×Bulk density=Acoustic Impedance (AI)) responds in the same direction to a variation of the volume of water and organic matter (OM) volume of the rocks, whereas the third tool (Deep Resistivity) reacts very differently in response to a change of one or other of these same components, in a three-pole diagram, with rock matrix, OM and water as the three components onto an Acoustic Impedance vs resistivity ratio function plane. The resistivity ratio function is the square root of the ratio between the water resistivity and the measured formation resistivity. The position of the curved line with OM=0% by volume is fixed connecting the rock matrix pole with that of water pole. The slope of the matrix-water curve is controlled by the tortuosity factor ‘a’ that is a function of the rock pore structure, grain size and level of compaction. Iso-OM curves run parallel to this 0% OM reference curve. The data points to be analysed can be calibrated accordingly by changing the resistivity of water (Rw) and the tortuosity factor (a) parameters. In a graph where the parameters used depend, for example, on the sonic velocity in the rock, the rock bulk density and on the electric resistivity of the formations, the iso-OM lines form a set of parallel curved lines. The OM is derived from there corresponding to each pair of values of the parameters measured in the well. The obtained organic matter volume is converted to Total organic carbon (TOC) in gram percentage using a conventional relation.

The present disclosure describes methods and systems, including computer-implemented methods, computer program products, and computer systems, for generating Angle Domain Common Image Gathers (ADCIGs). One computer-implemented method includes receiving, at a data processing apparatus, a set of seismic data associated with a subsurface region wherein the set of seismic data includes receiver signal data at a plurality of time steps; for each time step in the plurality of time steps: calculating a receiver wavefield based on the receiver signal data at the respective time step; separating a first direction receiver wavefield and a second direction receiver wavefield of the receiver wavefield using Hilbert transformation of the receiver signal data at the respective time step; and applying an optical flow process on the first direction receiver wavefield to calculate wavefield directions; and generating an Angle Domain Common Image Gather (ADCIG) based on the wavefield directions.

The present disclosure describes methods and systems, including computer-implemented methods, computer program products, and computer systems, for generating Angle Domain Common Image Gathers (ADCIGs). One computer-implemented method includes receiving, at a data processing apparatus, a set of seismic data associated with a subsurface region wherein the set of seismic data includes receiver signal data at a plurality of time steps; for each time step in the plurality of time steps: calculating a receiver wavefield based on the receiver signal data at the respective time step; separating a first direction receiver wavefield and a second direction receiver wavefield of the receiver wavefield using Hilbert transformation of the receiver signal data at the respective time step; and applying an optical flow process on the first direction receiver wavefield to calculate wavefield directions; and generating an Angle Domain Common Image Gather (ADCIG) based on the wavefield directions.

A method is described for seismic imaging that will produce a seismic image with correctly focused and positioned reflectors. This is accomplished by adding physical geological information to a beam tomography process to generate an updated earth model for the seismic imaging. The method may be executed by a computer system.