Method for characterizing subterranean formation is described. One method involves injecting a fluid into an active well of the subterranean formation at a pressure sufficient to induce one or more hydraulic fractures. Measuring, via a pressure sensor, a poroelastic pressure response caused by inducing of the one or more hydraulic fractures. The pressure sensor is in at least partial hydraulic isolation with the one or more hydraulic fractures.

A method for conducting an earth reservoir process includes receiving a stress field of a reservoir that includes a pore pressure field for a rock volume, selecting a search radius extending from a grid cell of interest, and substituting a pore pressure from a plurality of surrounding grid cells within the selected radius for the pore pressure of the grid cell of interest and determining if a critical stress state exists for each of the substituted pore pressures. The method further includes determining a shortest distance to a grid cell in the plurality of surrounding grid cells having a pore pressure that yields a critical stress state when substituted in the grid cell of interest and conducting the earth reservoir process with earth reservoir process apparatus using a parameter related to the determined shortest distance.

The present invention relates to a method of determining present-day horizontal stresses in geological formations. The method comprises dividing the received well data in a plurality of contiguous sets of data i, a set of data For each set of data i in the plurality of sets of data, determining, at least parameters P.sup.i, a pressure in subsoil i, b.sup.i, a Biot coefficient i, .sup.i, a Poisson's ratio i, .sub..sup.i, a vertical constraints in subsoil i, E.sup.i, a Young's modulus i, .sup.i, a thermal expansion coefficient, and T.sup.i, and a subsoil temperature. The method further comprises, i, computing and outputting the horizontal constraints.

Systems and methods for transferring logging data from an offset well location to a target well location by adjusting the logging data to account for the difference in correlated depths between the target well and the offset well where logging data is acquired.

One embodiment of generating a pore pressure prediction through integration of seismic data and basin modeling includes crossplotting seismically derived velocities and effective stress at spatial coordinates; defining seismic transform functions and an uncertainty range from the crossplotting; transforming the seismically derived velocities into calculated effective stress using selected seismic transform functions and calculating pore pressure using an equation transforming the calculated effective stress into calculated pore pressure; identifying a subset of the selected seismic transform functions, where the subset is identified in response to the calculated pore pressure being adequate based on a comparison; using an inverse of the subset to convert the effective stress from the basin model into basin model derived velocities; building a hybrid velocity model by selecting velocities from the basin model derived velocities or from the seismically derived velocities in each region; and generating a digital seismic image using the hybrid velocity model.

Disclosed are methods, systems, and computer-readable medium to perform operations for calculating pore pressure in a reservoir, the operations including: receiving input data including: (i) a rock density in the reservoir, (ii) seismic data measured in the reservoir, and (iii) pore pressure measurements from a Modular Formation Dynamic Tester (MDT); calculating, based on the rock density, an overburden pressure volume of the reservoir; generating, based on the overburden pressure volume, an overburden pressure volume of the reservoir; generating, based on the seismic data, an acoustic impedance volume of the reservoir; calculating, based on the overburden pressure and the MDT pore pressure measurements, an effective stress volume of the reservoir; generating, based on the effective stress and overburden volumes, an estimated pore pressure volume of the reservoir; and calculating, based on the estimated pore pressure volume, a pore pressure gradient map indicative of the pore pressure in the reservoir.

A method for determining spatial distribution of permeability in a subsurface formation using passive seismic signals includes determining a spatial distribution of a fracture network generated by the pumping of hydraulic fracturing fluid using detected seismic signals resulting from the pumping. A bulk permeability of the fracture network is determined using the detected seismic signals. A formation permeability is determined in each cell of a cellular grid containing the fracture network resulting from the pumping of the hydraulic fracturing fluid. The calculated formation permeability in each cell is then scaled such that the average formation permeability is substantially equal to the bulk permeability to calculate the permeability distribution.

A method of predicting pore pressure based on seismic data can include obtaining seismic inversion data based in part on seismic data collected from a formation. The method also includes calculating a pore-pressure transform, wherein the pore-pressure transform comprises parameters derived using measured pore pressure data, upscaled sonic logs, and density logs, wherein the pore-pressure transform comprises an objective function to reduce unphysical variations in predicted pore pressure corresponding to depth. Additionally, the method can include adjusting the pore-pressure transform for sampling bias caused by pore pressure measurements being restricted to a plurality of lithologies by accounting for a difference between upscaled seismic velocities and average sonic velocities within each of the lithologies. Furthermore, the method can include generating pore pressure prediction values based on the pore-pressure transform for the lithologies and the seismic inversion data, and modifying a seismic model based on the generated pore pressure prediction values.

Properties of underground formations are obtained by performing simultaneous geostatistical inversion of two or more seismic datasets acquired over the same area. These methods enable simultaneous estimating quantitative changes in a hydrocarbon-producing field.

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.