Abstract: A method for evaluating and controlling a washout region of a wellbore placed in a formation includes: obtaining information about the wellbore and the formation; establishing a washout indicator function as a function of time and location; computationally determining whether the washout region exists by calculating the washout indicator function on a cross section of the wellbore and the formation, at each depth in a specific depth range; and upon finding presence of the washout region in the specific depth range, quantifying the washout region. The washout indicator function returns: a negative value for a point within the formation; a positive value for a point within the washout region; and zero for a point on a boundary.

Abstract: A method for selecting lost circulation materials (LCM) for boring a well involves determining, for a multitude of LCM blends, a multitude of overall scores based on characteristics associated with each of the multitude of LCM blends, and establishing a list of LCM blend candidates. Establishing the list of LCM blend candidates involves including a first of the multitude of LCM blends in a list of LCM blend candidates based on a first overall score associated with the first LCM blend, and excluding a second of the multitude of LCM blends from the list of LCM blend candidates, based on a second overall score associated with the second LCM blend. The first overall score is greater than the second overall score.

Abstract: A computer-implemented method for determining near-wellbore stress and state in a drilled well includes: importing input data of a form of data files; calculating stress and pressure parameters along a wellbore path from the input data imported; displaying one or more of the input data and the calculated stress and pressure parameters along a well path of the drilled well; receiving, by a graphical user interface (GUI), a user selection of a depth at which distribution of the near-wellbore stress and state around a wellbore is determined; in response to receiving the user selection, calculating near-wellbore parameters describing the near-wellbore stress and state around the wellbore; and displaying, by the GUI, the calculated near-wellbore parameters around the wellbore.

Abstract: A method of constructing a mechanical earth model (MEM) includes integrating a density logging data set to compute vertical stress and applying correlation models or equations to estimate a pore pressure and mechanical properties. The method also includes calibrating the pore pressure with drill stem test data, calibrating the mechanical properties with laboratory tests on core plugs or on rock cuttings, estimating a minimum horizontal stress using correlation models, and calibrating the minimum horizontal stress with minifrac tests. The method further includes estimating a maximum horizontal stress using the correlation models while assuming one or more correlation parameters, calibrating the maximum horizontal stress with a global pattern of tectonic strains and a basin stress regime, evaluating one or more breakout regions using the MEM, a trajectory of a well, and a geometry of a pilot hole, and comparing the one or more breakout regions and a caliper logging data set.

Abstract: Systems and methods for determining breakdown overpressure are disclosed. The methods may include obtaining a borehole radius and a porosity value in a borehole; determining a rock brittleness index value from the porosity value; determining a breakdown overpressure radius from the rock brittleness index value and the borehole radius; and determining a breakdown overpressure from the breakdown overpressure radius. The methods may further include planning a fracking operation in a well based on the determined breakdown overpressure.

Abstract: A system for determining cation exchange capacity includes: a container containing a solution having a solute and a solvent; a sample; a pressure sensor configured to measure an osmotic pressure of the sample generated by a flow of the solution through the sample; and a control unit configured to determine the cation exchange capacity of the sample based on the osmotic pressure measured by the pressure sensor.

Abstract: Systems and methods are disclosed. The method includes obtaining well data for a fluid-saturated rock and obtaining a poroelastodynamic relationship linking a deformation of the fluid-saturated rock to a poromechanical property of the fluid-saturated rock. The method further includes determining the poromechanical property of the fluid-saturated rock by applying a vector operator to the poroelastodynamic relationship. The method still further includes determining a value of the poromechanical property by substituting the well data into the vector-operated poroelastodynamic relationship.

Abstract: A method includes obtaining total stresses and pore pressures of each porous medium of a formation, determining a first and second set of effective stresses for the formation, determining an individual collapse and fracturing mud weight for each porous medium of the formation using a first set of associated failure criteria, wherein the first set of associated failure criteria are based on the first set of effective stresses, determining an overall collapse and fracturing mud weight for the formation using a second set of associated failure criteria, wherein the second set of associated failure criteria is based on the second set of effective stresses, determining a mud weight window for the formation using the individual collapse mud weight, the individual fracturing mud weight, the overall collapse mud weight, and the overall fracturing mud weight, and transmitting a command to a drilling system based on the mud weight window.

Abstract: Systems and methods for determining a connected porosity and a non-connected porosity in a fluid-saturated hydrocarbon reservoir are disclosed. The methods include obtaining at least one rock sample from the fluid-saturated hydrocarbon reservoir, determining, using a petrophysical sample analyzer, at least one petrophysical parameter of the rock sample, and measuring at least one of an elastic wave velocity and an elastic wave attenuation for each of a plurality of wave frequencies. The methods further include determining, using a computer processor, the connected porosity and the non-connected porosity of the rock sample using a dual-porosity single-permeability model based, at least in part, on at least one petrophysical parameter and at least one of the elastic wave velocity and the elastic wave attenuation.

Abstract: A method of determining rock matrix and fracture permeability to perform a reservoir fluid flow simulation. The method includes: obtaining a petrophysical characterization of a formation sample, measuring a first and second elastic wave velocity of the formation sample at a first and second frequency, calculating an average rock matrix density and an average porosity of the formation sample, determining a set of calculated elastic wave velocities for the first and second frequencies over a range of candidate permeabilities, and determining a rock matrix permeability and a fracture permeability based on the set of calculated elastic wave velocities at the first and second frequency respectively. The method further including performing a reservoir fluid flow simulation based, at least in part, on at least one of the rock matrix permeability and the fracture permeability.

Abstract: A system and method for determining a mud-weight window is disclosed. The method includes determining, for each of a plurality of borehole-formation training models, a fracture mud weight using a first physics-based method and a collapse mud weight using a second physics-based method, and training, using the plurality of borehole-formation training models, an artificial intelligence (AI) network to predict the fracture and collapse mud weights for a borehole formation model. The method further includes determining, using the trained AI network, an AI fracture and an AI collapse mud weight from an observed borehole-formation model, and a search window surrounding each AI mud weight. The method further includes predicting a final fracture mud weight within the fracture search window using the first physics-based method and a final collapse mud weight within the collapse search window using the second physics-based method, and determining the mud-weight window bounded by the two final mud weights.

Abstract: A method for predicting a formation property of a formation, including the steps of: drilling a first well that penetrates the formation, obtaining well properties from the first well, determining a measured formation property from the first well, determining a correlation function that estimates a predicted formation property from the well properties, wherein the correlation function comprises coefficients, calibrating the correlation function by modifying the coefficients until the predicted formation property best matches the measured formation property, drilling a second well that penetrates the formation, obtaining well properties from the second well, determining the formation property from the second well by applying the correlation function with the modified coefficients to the well properties.

Abstract: A method includes obtaining total stresses and pore pressures of each porous medium of a formation, determining a first and second set of effective stresses for the formation, determining an individual collapse and fracturing mud weight for each porous medium of the formation using a first set of associated failure criteria, wherein the first set of associated failure criteria are based on the first set of effective stresses, determining an overall collapse and fracturing mud weight for the formation using a second set of associated failure criteria, wherein the second set of associated failure criteria is based on the second set of effective stresses, determining a mud weight window for the formation using the individual collapse mud weight, the individual fracturing mud weight, the overall collapse mud weight, and the overall fracturing mud weight, and transmitting a command to a drilling system based on the mud weight window.

Abstract: A method may include determining time-derivative pressure data based on pressure data regarding a pump system that is performing a hydraulic stimulation operation in a geological region. The method may further include determining a moving average value based on the time-derivative pressure data and a predetermined time window. The method may further include determining a flow rate adjustment for the pump system based on the moving average value, an update interval for adjusting flow rates, and a predetermined flow rate rule. A size of the predetermined time window may be different from the update interval. The method may further include using smoothed pressure data to determine time-derivative pressure data. The method may further include determining a flow rate adjustment for the pump system based on the time-derivative pressure data derived from the smoothed pressure data.

Abstract: A method for measuring a fracture permeability and a matrix permeability of a naturally fractured cylindrical rock sample, includes sealing both flat ends of the cylindrical sample; immersing the naturally fractured cylindrical rock sample in a fluid, and attaching an axial and a radial strain sensor to the curved surface of the sample. Furthermore, the method includes attaching a signal generator to one flat end of sample, and a signal receiver to the other flat end of the sample, and generating a harmonic excitation using the signal generator at a plurality of frequencies and recording the excitation at each of the plurality of frequencies. The method includes calculating an elastic wave propagation attribute at each of the plurality of frequencies, and inverting the elastic wave propagation attribute at each of the plurality of frequencies to determine the fracture permeability and the matrix permeability of the naturally fractured cylindrical rock sample.

Abstract: A method may include determining time-derivative pressure data based on pressure data regarding a pump system that is performing a hydraulic stimulation operation in a geological region. The method may further include determining a moving average value based on the time-derivative pressure data and a predetermined time window. The method may further include determining a flow rate adjustment for the pump system based on the moving average value, an update interval for adjusting flow rates, and a predetermined flow rate rule. A size of the predetermined time window may be different from the update interval. The method may further include using smoothed pressure data to determine time-derivative pressure data. The method may further include determining a flow rate adjustment for the pump system based on the time-derivative pressure data derived from the smoothed pressure data.

Abstract: A method for measuring a fracture permeability and a matrix permeability of a naturally fractured cylindrical rock sample, includes sealing both flat ends of the cylindrical sample; immersing the naturally fractured cylindrical rock sample in a fluid, and attaching an axial and a radial strain sensor to the curved surface of the sample. Furthermore, the method includes attaching a signal generator to one flat end of sample, and a signal receiver to the other flat end of the sample, and generating a harmonic excitation using the signal generator at a plurality of frequencies and recording the excitation at each of the plurality of frequencies. The method includes calculating an elastic wave propagation attribute at each of the plurality of frequencies, and inverting the elastic wave propagation attribute at each of the plurality of frequencies to determine the fracture permeability and the matrix permeability of the naturally fractured cylindrical rock sample.

Abstract: A method includes capturing multivariate time-series data comprising two or more data sets from a system captured over a past time period and a present time period, applying at least two sliding time windows to the multivariate time-series data in determining respective data matrices, computing an orthonormal matrix for each of the data matrices, wherein the orthonormal matrix is a signature of fluctuation patterns of a respective data matrix, computing a difference between at least two of the data sets in the past and the present time periods through the orthonormal matrices, and detecting a fault in at least one of the systems by comparing the difference to a threshold.

Abstract: A method includes determining whether transformer phases should be permuted. The method includes, responsive to a determination that the transformer phases should be permuted, permuting the transformer phases, based on historical aging information of transformer input phases, to cause transformer input phases with higher ages to be connected to transformer output phases with lower output loads and transformer input phases with lower ages to be connected to transformer output phases with higher output loads. Multiple apparatus and program products are also disclosed.

Abstract: A method for solving a two-stage non-linear stochastic formulation for the economic dispatch problem under renewable-generation uncertainty. Certain generation decisions are made only in the first stage and fixed for the subsequent (second) stage, where the actual renewable generation is realized. The uncertainty in renewable output is captured by a finite number of scenarios. Any resulting supply-demand mis-match must then be alleviated using high marginal-cost power sources that can be tapped in short time frames. The solution implements two outer approximation algorithms to solve this nonconvex optimization problem to optimality including the application of a decomposition approach derived from the Alternating Direction Method of Multipliers (ADMM) algorithm.