A method of seismic exploration above a region of the subsurface of the earth containing structural or stratigraphic features conducive to the presence, migration, or accumulation of hydrocarbons comprises setting a tow depth of a resonant seismic source, producing a resonant frequency at a first amplitude with the resonant seismic source at the tow depth, detecting a depth excursion from the tow depth, reducing an amplitude of the mass from the first amplitude to a second amplitude, preventing the mass from contacting at least one of the first end stop or the second end stop based on reducing the amplitude to the second amplitude, correcting the depth excursion to return the resonant seismic source to the tow depth, and increasing the amplitude from the second amplitude to produce the resonant frequency with the resonant seismic source at the tow depth.

A computer-implemented method for augmented inversion and uncertainty quantification for characterizing geophysical bodies is disclosed. The method includes machine-learning-augmented inversion that also facilitates the characterization of uncertainties in geophysical bodies. The method may further estimate wavelets without a well-log calibration, thereby enabling a pre-discovery exploration phase when well log data is unavailable. The machine learning component incorporates a priori knowledge about the subsurface and physics, such as distributions of expected rock types and rock properties, geological structures, and wavelets, through learning from examples. The methodology also allows for conditioning the characterization with the information extracted a priori about the geobodies, such as probabilities of rock types, using other analysis tools. Thus, the conditioning strategy may make the inversion more robust even when a priori distributions are not well balanced. Using the method, a scenario testing workflow may evaluate different candidate subsurface models, facilitating the management of uncertainty in decision-making processes.

A production monitoring system includes a distributed acoustic sensing subsystem that includes a first optical fiber for a distributed acoustic sensing signal and a distributed temperature sensing subsystem that includes a second optical fiber for a distributed temperature sensing signal. The production monitoring system, also includes a cable positioned in a wellbore penetrating through one or more subterranean formations. The distributed acoustic sensing subsystem is communicatively coupled to the cable through the distributed temperature sensing subsystem. The cable includes one or more optical fibers used to obtain optical fiber measurements pertaining to the distributed acoustic sensing signal and the distributed temperature sensing signal. The optical fibers include a sensing fiber that is common between the distributed acoustic sensing subsystem and the distributed temperature sensing subsystem. The distributed acoustic sensing subsystem, receives at least a portion of the optical fiber measurements from the sensing fiber through the distributed temperature sensing subsystem.

Methods and apparatuses for seismic data processing perform a least-squares reverse time migration method in which surface-attribute-independent coefficients for the surface attribute gathers are demigrated to reduce the computational cost.

A method may include obtaining seismic data regarding a geological region of interest. The method may further include obtaining a property model regarding the geological region of interest. The method may further include determining an adjoint migration operator based on the property model. The method may further include updating the property model using the seismic data and a conjugate gradient solver in a least-squares reverse time migration to produce a first updated property model. The conjugate gradient solver is based on the adjoint migration operator. The method may further include updating the first updated property model using a threshold shrinkage function to produce a second updated property model. The threshold shrinkage function comprises a sign function and a maximum function that are applied to the first updated property model. The method may further include generating a seismic image of the geological region of interest using the second updated property model.

Characteristics of a reservoir may be used to generate multiple models of the reservoir with hydraulic fractures. Simulated configurations of the hydraulic fractures in the models may be used to select one or more of the models as representative model(s) for the reservoir. The representative model(s) may be used in development of the reservoir. Hydraulic fracturing may increase productivity at shale and tight rock reservoir by creating more effective flow paths to production.

A system is provided. The system includes a plurality of seismic sensors and a computer device. The computer device is programmed to a) store a plurality of distances between each of the plurality of seismic sensors; b) store one or more fingerprints of a signal to be detected; c) receive a first signal transmitted from a first seismic sensor of the plurality of seismic sensors; d) receive the first signal transmitted from a second seismic sensor of the plurality of seismic sensors; e) compare the first signal to the one or more fingerprints of the signal to be detected; and f) determine a direction of travel of the first signal based on the distance between the first seismic sensor and the second seismic sensor, the first time, and the second time.

A method for determining microseismic events. The method may include measuring a seismic travel time of a microseismic event with a fiber optic line disposed in a first wellbore, forming a probability density function for the microseismic event based at least in part on the seismic travel time measurement, modifying the probability density function by applying one or more constraints to form a modified probability density function, identifying one or more most probable source locations from the modified probability density function, and forming a microseismic event cloud from the one or more most probable source locations.

Disclosed is an in-situ stress evaluation method based on a wellbore mechanical instability collapse, including: selecting a mechanical instability collapse wellbore section and classifying a data, obtaining a deep in-situ stress according to a structural strain coefficient, establishing a structural strain coefficient equation based on a wellbore stress critical equilibrium condition, obtaining the structural strain coefficient by using a least squares method and obtaining a horizontal principal stress, and estimating a reasonableness of the deep in-situ stress. The method selects data of the wellbore mechanical instability collapse and classify the data to establish a stress critical equilibrium equation based on a strain coefficient and solve an overdetermined equation based on a critical collapse formation information restriction, so as to obtain a maximum horizontal principal stress and a minimum horizontal principal stress.

Systems and methods for determining perforation orientations of a subterranean formation for a hydraulic fracturing treatment are presented. The method comprises identifying in-situ stresses for a portion of a wellbore formed from a terranean surface into a subterranean formation. The method also includes transforming the in-situ stresses from a global coordinate system to a wellbore coordinate system at a perforation cluster of the wellbore that comprises at least one perforation tunnel for a hydraulic fracturing treatment. The in-situ stresses are transformed from the wellbore coordinate system to a perforation coordinate system through at least one rotation matrix. Pressure coefficients and a breakdown pressure for each trial perforation phase angle at a perforation cluster determined, and a perforation point in the wellbore coordinate system is calculated for each trial perforation phase angle of the perforation cluster. The perforation point in the wellbore coordinate system is transformed to the translated global coordinate system for each trial perforation phase angle. A target perforation phase angle is selected at a minimum breakdown pressure for the perforation cluster, and a perforation azimuth and perforation dip is calculated for the perforation cluster at the minimum breakdown pressure for the target perforation phase angles.