Disclosed herein are methods for predicting pore pressure in geological environments. Aspects of the disclosure describe details relating to performing geomechanical modeling for a target location in order to obtain a surrogate stress at the target location and predicting pore pressure by coupling velocity data (e.g., seismic and/or sonic) with the surrogate stress. Aspects of the disclosure can be used to obtain improved predictions of pore pressure in subsurface environments, especially in basins with complex geologic histories, and in practice to improve the safe design of casing, wellbore trajectory, and overall borehole stability.

Methods and systems are provided that identify relatively large anisotropic horizontal stresses in a formation based on (i) azimuthal variations in the compressional and shear slownesses or velocities of the formation measured from ultrasonic data acquired by at least one acoustic logging tool as well as (ii) cross-dipole dispersions of the formation measured from sonic data acquired by the at least one acoustic logging tool. In addition, the azimuthal variations in the compressional and shear slownesses or velocities of the formation and dipole flexural dispersions of the formation can be jointly inverted to obtain the elastic properties of the rock of the formation in terms of linear and nonlinear constants and the magnitude of maximum horizontal stress of the formation. A workflow for estimating the magnitude of the maximum horizontal stress can employ estimates of certain formation properties, such as overburden stress, magnitude of minimum horizontal stress, and pore pressure.

Provided is a method for determining convergence in full wavefield inversion (FWI) of 4D seismic (time-lapse seismic: 3D seismic surveys acquired at different times with the first survey termed as the baseline and subsequent surveys termed as monitors). FWI applied to field seismic data includes iteratively solving for subsurface property models and model difference between monitor and baseline. Iteration occurs until the model difference is sufficiently converged. Rather than determining convergence by examining an entire subsurface region of the models and/or the model difference, subparts of the subsurface region models and/or the model difference are examined in order to determine convergence. For example, different regions behave differently, include the target reservoir region (where hydrocarbon is present) and the background region that is outside the target reservoir region. Thus, transforming the subregions of the models and/or the model difference and analyzing the transformations may indicate convergence of the overall model difference.

A method of evaluating a subterranean formation includes conveying a tool along a borehole. The tool includes a transmitter that transmits a drive pulse and a receiver that receives at least one formation response to the drive pulse. The method further includes calculating a signal-to-noise ratio of the at least one formation response and comparing the signal-to-noise ratio to a programmable threshold. The method further includes determining, based on the comparing, an adjusted drive pulse to transmit and transmitting the adjusted drive pulse. The method further includes and receiving at least one formation response to the adjusted drive pulse and deriving formation data from the at least one formation response to the adjusted drive pulse. The method further includes displaying a representation of the formation based on the formation data.

A method is described for seismic imaging including generating extended image gathers by extended reverse time migration of a seismic dataset using an earth model; processing the extended image gathers to generate processed image gathers; performing extended modeling based on the processed image gathers to generate a modeled seismic dataset; enhancing the processed image gathers to generate an enhanced image; performing extended modeling based on the enhanced image gathers to generate a modeled enhanced dataset; differencing the modeled enhanced dataset and the modeled seismic dataset to determine a data residual; inverting the data residual to generate a model residual; updating the earth model based on the model residual to create an updated earth model; performing seismic imaging of the seismic dataset using the updated earth model to create an improved seismic image. The method may be executed by a computer system.

There is disclosed a system and method for analyzing geological features of a reservoir, such as a subterranean hydrocarbon reservoir undergoing changes during different stages of its production, by utilizing an artificial neural network to learn from hydrocarbon reservoir production project. In an aspect, there is provide a system and method for utilizing data collected from 4D seismic studies in order to train an artificial neural network to recognize how physical properties of a hydrocarbon reservoir change over time, as the hydrocarbon reservoir is produced. In an embodiment, the system and method are adapted to generate and obtain a plurality of image slices or image planes derived from a 3D seismic baseline and at least one monitor acquired over the course production of the hydrocarbon reservoir. Corresponding 2D image slices derived from the 3D seismic baseline and a subsequent monitor are correlated and matched and are then used to train an artificial neural network to create a predictive model of how the reservoir may change over time.

Enhanced seismic velocity models are generated using a geomechanical model. A tomographic velocity model is generated based on raw seismic data. One or more initial seismic images are generated based at least partially on the tomographic velocity model. Geomechanical data and the initial seismic images are used to generate a geomechanical model. The geomechanical model produces geomechanical outputs that are used to generate a geomechanical velocity model. A second tomographic velocity model is generated based on the first tomographic velocity model and the geomechanical velocity model.

A method for applying separated wave-field imaging onshore (1) by artificially creating up-going and down-going fields and (2) by using these fields in a migration algorithm. If there are any surface multiples in the data, the resulting image created using the migration algorithm will be distorted by the unknown free-surface reflection coefficient. In fact, the surface multiples may be generated with a complex series of reflection coefficients. The distortions found in the resulting image created using the migration algorithm are then removed.

A method can include receiving information associated with an interface between a first medium and a second medium where the information includes sensor data; based on at least a portion of the information, estimating wave properties that include elastic properties, depth-dependent properties and horizontal slowness; and, based on the estimated wave properties, calculating an orientation of a sensor utilized to acquire at least a portion of the sensor data.

Methods comprising electronically receiving information of a reflection of a known first sound pulse, electronically receiving information of a reflection of a known second sound pulse, determining, by a processor, a change in a first property between a known first sound pulse and a reflection of the known first sound pulse, determining, by the processor, a change in a second property between a known second sound pulse and a reflection of the known second sound pulse, comparing, by the processor, the change in the first property of the first known sound pulse with the change in the second property of the second known sound pulse, and determining, by the processor, a condition of a well in response to the comparison of the change of the first property with the change of the second property are disclosed. Systems for determining a condition of a well are also disclosed.