A method for calculating a velocity model for a subsurface of the earth. The method includes receiving (200) measured seismic data d; calculating (204) predicted seismic data p; selecting (206) a matching filter w that when applied to one of the measured seismic data d or the predicted seismic data p reproduces the other one of the measured seismic data d or the predicted seismic data p; selecting (208) a misfit function J that calculates (1) a distance between the matching filter w and a Dirac Delta function or (2) a travel time shift associated with the measured seismic data; and calculating (218) a new velocity model using the misfit function J, the measured seismic data d, and the predicted seismic data p. The measured seismic data d includes wavefields generated by a seismic source and the wavefields propagate through the subsurface where they are attenuated and reflected, and the attenuated and reflected wavefields are recorded by plural seismic receivers.

The invention concerns a method for evaluating a geophysical survey acquisition geometry over a region of interest. The method comprises determining a location of a plurality of base camps in respect of a determined minimal surface density of base camps, determining a first set of locations of a plurality of receivers in respect of a determined minimal surface density of receivers, generating a first synthetic geophysical dataset based on the first geophysical survey acquisition geometry, processing the first synthetic geophysical dataset for obtaining a first simulated image of the subsurface of the region of interest using a geophysical processing algorithm and an a priori subsurface model, and calculating a first objective function dependent of at least a first quality index of the first simulated image of the subsurface of the region of interest.

A method for calculating a velocity model for a subsurface of the earth. The method includes receiving (200) measured seismic data d; calculating (204) predicted seismic data p; selecting (206) a matching filter w that when applied to one of the measured seismic data d or the predicted seismic data p reproduces the other one of the measured seismic data d or the predicted seismic data p; selecting (208) a misfit function J that calculates (1) a distance between the matching filter w and a Dirac Delta function or (2) a travel time shift associated with the measured seismic data; and calculating (218) a new velocity model using the misfit function J, the measured seismic data d, and the predicted seismic data p. The measured seismic data d includes wavefields generated by a seismic source and the wavefields propagate through the subsurface where they are attenuated and reflected, and the attenuated and reflected wavefields are recorded by plural seismic receivers.

A method is described for calibrating seismic data based on statistical properties of shale derived from either well logs in a volume of interest or a global database of statistical properties of shale. The method may be executed by a computer system.

A method for determining a favorable time window of an infill well of an unconventional oil and gas reservoir, which comprises the following steps: S1, establishing a three-dimensional geological model with physical properties and geomechanical parameters; S2, establishing a natural fracture network model in combination with indoor core-logging-seismic monitoring; S3, calculating complex fractures in hydraulic fracturing of parent wells; S4, establishing an unconventional oil and gas reservoir model and calculating a current pore pressure field; S5, establishing a dynamic geomechanical model and calculating a dynamic geostress field; S6, calculating complex fractures in horizontal fractures of the infill well in different production times of the parent wells based on pre-stage complex fractures and the current geostress field; S7, analyzing a microseismic event barrier region and its dynamic changes in infill well fracturing; and S8, analyzing the productivity in different infill times, and determining an infill time window.

Methods and a device for detecting physical intrusion are providing, the device including a vibration sensor, a processor, a transmitter, a battery, and a conductive wire connecting the vibration sensor and the processor. The vibration sensor is affixed to a first part of the device, and the processor, transmitter, and battery are affixed to a second part of the device. The first and second parts, when attached together, form a case containing the conductive wire. The device performs steps of: sampling a set of seismic signals from the vibration sensor, determining that the set of seismic signals matches a seismic threat pattern, and responsively issuing an intrusion alert.

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.

A method can include receiving values of an inversion based at least in part on seismic amplitude variation with azimuth (AVAz) data for a region of a geologic environment; based at least in part on the received values, computing values that depend on components of a second-rank tensor a.sub.ij; selecting a fracture height for fractures in the geologic environment; selecting an azimuth for a first fracture set of the fractures; based at least in part on the values for the second-rank tensor a.sub.ij, the fracture height and the selected azimuth, determining an azimuth for a second fracture set of the fractures; and generating a discrete fracture network (DFN) for at least a portion of the region of the geologic environment where the discrete fracture network (DFN) includes fractures of the first fracture set and fractures of the second fracture set.

A system and method combines model-based inversion and supervised neural networks to develop high resolution rock property volumes from surface seismic data. These volumes have higher frequency and are calibrated to fit well log data. In addition to rock volumes, a Reflection Coefficient (RC) volume is derived from the acoustic impedance volume. The RC volume has much higher frequency, better lateral continuity, and ties to the well logs better than conventional seismic or frequency enhanced data. By interpreting and mapping with this RC volume, a much more accurate depth model can be built, which allows for a horizontal well to be accurately drilled.

The invention relates to petroleum seismic exploration, and more specifically to a method for gas-bearing reservoir characterization using logging information. In the method, logging information is used as a constraint to indirectly characterize the distribution range of the gas-bearing reservoir by determining the upper and lower boundaries. In addition, this method enables the automatic determination of the optimal calculation parameters according to the characteristics of input data, allowing for more accurate results.