A method includes receiving a first transition probability matrix (TPM) of a subsurface region, wherein the TPM defines, for a given lithology at a current depth sample (or micro-layer), a probability of particular lithologies at a next depth sample (or micro-layer), receiving seismic data for the subsurface region, utilizing the first TPM and the seismic data to generate first pseudo wells, calculating a second TPM from the first pseudo wells, determining whether the second TPM is consistent with the first TPM, and utilizing the first pseudo wells to characterize a reservoir in the subsurface region when the second TPM is determined to be consistent with the first TPM.

A method of performing a fracture operation at a wellsite is provided. The wellsite has a fracture network therein with natural fractures. The method involves stimulating the wellsite by injecting an injection fluid with proppant into the fracture network, obtaining wellsite data comprising natural fracture parameters of the natural fractures and obtaining a mechanical earth model of the subterranean formation, defining the natural fractures based on the wellsite data by generating one or more realizations of the natural fracture data based on a statistical distribution of natural fracture parameters, meters, generating a statistical distribution of predicted fluid production by generating a hydraulic fracture growth pattern for the fracture network over time based on each defined realization and predicting fluid production from the formation based on the defined realizations, selecting a reference production from the generated statistical distribution, and optimizing production and uncertainty by adjusting the stimulating operations based on the selecting.

The disclosure relates to methods and systems for analyzing an image of the formation intersected by a borehole. One of the methods determines a local apparent dip of the borehole at least at a measured depth i represented on the image, applies at least a window to the image, wherein each of the windows includes one of the measured depth i and is shaped as a function of the determined local dip at the corresponding measured depth i, compares a texture of at least a first zone of each window and a texture of at least a second zone of said window, wherein each of the first and second zones are adjacent and shaped as a function of the determined dip. Based on the comparison, the method determines at least a location of a texture boundary and derives a property of the formation. The other method includes determine locations of the texture boundaries, segmenting the image as a function of the texture boundaries, and perform clustering of the segments in order to determine a facies of the formation.

Systems, methods, and computer programs for monitoring production of fluids from a subterranean formation includes receiving, from a first sensor array at a first time, a first set of electromagnetic signals generated by an electroseismic or seismoelectric conversion of seismic signals caused, at least in part, by the production of fluid from the subterranean formation; receiving, from the first sensor array at a second time, a second set of electromagnetic signals generated by an electroseismic or seismoelectric conversion of seismic signals caused, at least in part, by the production of fluid from the subterranean formation; and determining one or more reservoir properties based, at least in part, on the first and second sets signals received from the first sensor array. The first sensor array are arranged to monitor the production operation.

Methods, systems, and apparatus, including computer programs encoded on a computer storage medium, to generate generating geo-cellular models with improved lacunae. In one aspect, a method includes receiving a seismic dataset of a surveyed subsurface, and the seismic dataset includes seismic porosities in depth of the surveyed subsurface. Seismic porosities resampled into a three dimensional (3D) geological fine layer model grid. Seismic porosities at well locations are extracted using the 3D geological fine layer model grid. Log porosities and the seismic porosities are upscaled into coarse layers, and the coarse layers are identical for all the well locations. Match factors are determined based on differences between the upscaled log porosities and the downscaled seismic porosities. Co-krig the log porosities are correlated with the 3D geological fine layer model grid using the match factors as a soft constraint to produce a final 3D model.

An exemplary embodiment of the invention relates a method for determining hydraulic permeability of rocks in a subsurface region, the method comprising: in-situ measuring and/or calculating at least one of independent seismic velocities of rocks at different locations in said subsurface region; determining at least one lithological unit in said subsurface region based on the measured seismic velocities; for the at least one lithological unit, acquiring at least one rock sample at an at least one location of said subsurface region; measuring the rock-sample porosity and permeability as functions of stress; measuring and/or calculating of at least one of independent seismic velocities of said at least one rock sample as functions of stress; computing the stiff and compliant porosity of said at least one rock sample; computing numerical coefficients of a given analytical permeability model based on the stiff and compliant porosities; computing coefficients of a given analytical model of an elastic-compliance characteristic of the rock based on the stiff and compliant porosity; computing the stiff and compliant porosity for a plurality of other locations in said subsurface region; and computing the permeability of rocks belonging to said at least one lithological unit, for said at least one location in said subsurface region and for said plurality of other locations in said subsurface region.

A method of operating a reservoir simulator can include performing a time step of a reservoir simulation using a spatial reservoir model that represents a subterranean environment that includes a reservoir to generate simulation results for a first time where the simulation results include a front defined by at least in part by a gradient at a position between portions of the spatial reservoir model; predicting a position of the front for a subsequent time step for a corresponding second time using a trained machine model; discretizing the spatial reservoir model locally at the predicted position of the front to generate a locally discretized version of the spatial reservoir model; and performing a time step of the reservoir simulation using the locally discretized version of the spatial reservoir model to generate simulation results for the second time.

A method and system are described for communicating within a system, which includes a plurality of communication nodes disposed along tubular members in a wellbore. The method includes constructing a communication network and installing the communication nodes along the tubular members. The communication nodes are used to monitor for the presence and/or quantity of sand in the tubular members by analyzing how the contents of the tubular members acoustically affect the signals transmitted between the communication nodes.

The present disclosure generally relates to a real-time synthetic logging method for optimizing one or more operations in a well. The method generally includes receiving measurements of one or more parameters in real time while performing operations in the well, the measurements being captured without using tools that include active nuclear sources. The method further includes providing the measurements as input to a machine learning algorithm (MLA) that is trained using historical or training well data. The method further includes generating, using the MLA and based on the measurements, a synthetic mechanical property log of the well. The method further includes generating, based on the synthetic mechanical property log, optimized parameters for at least one operation selected from the following list: drilling the well in real-time; steering the well in real-time; and stimulating a reservoir in real-time.

A method of fluid substitution, wherein an initial data set is provided, wherein a substituted data set is provided, wherein a rock physics model is provided, wherein the initial data set includes initial data of a geophysical parameter and initial fluid data, and wherein the substituted data set includes substituted fluid data. The method includes using the model and the initial data set to calculate first calculated data of the geophysical parameter, using the model and the substituted data set to calculate second calculated data of the geophysical parameter, calculating the difference between the first calculated data of the geophysical parameter and the second calculated data of the geophysical parameter, and applying the difference to the initial data of the geophysical parameter to produce substituted data of the geophysical parameter.