Halliburton Energy Services, Inc.

Landmark Graphics Corporation

John Andrew Quirein

Dingding Chen

Natasa Mekic

Mehdi Eftekhari Far

Harry D Smith, Jr

Ming Gu

Jeffery L Grable

Luis Emilio San Martin

Syed Hamid

Junsheng Hou

Daniel Francois Dorffer

Yi Zhou

Burkay Donderici

Christopher Michael Jones

Bin Dai

Weijun Guo

Reza Khalaj Amineh

James Elmer Galford

Larry Alan Jacobson

Orlando Dejesus

Philip Edmund Fox

Jerome Allen Truax

Ferhat Turker Celepcikay

Steve Zannoni

Arthur Chuen Hon Cheng

Charles Francis Stringer

Jacky Muri Wiener

Mahmoud Eid Selim

Daniel Robert Buller

James Michael Witkowsky

Glenn F Carpenter

Travis Lee Jeffers

Deepak Gokaraju

Christopher S McIlroy

Mehdi Eftekharifar

Example embodiments are described for a method and system for logging data processing in determining permeability anisotropy effects. A permeability anisotropy model is used to derive a relationship between formation permeability anisotropy and resistivity anisotropy in both TI and BA formations. Implementations can provide the permeability anisotropy plus the true reservoir (or sand) permeability by using an integrated interpretation of the MCI resistivity anisotropy measurements with conventional permeability logs from other sensors (e.g., NMR or sonic). Biaxial and triaxial permeability components of the permeability anisotropy tensor can be determined for application to synthetic and field log interpretations.

Permeability anisotropy assessment in subsurface anisotropic formations

Near real-time methodologies for maximizing return-on-fracturing-investment for shale fracturing. An example system can calculate, based on sonic data and density data, mechanical properties and closure stress of a portion of shale rocks for fracture modeling. The system can generate one or more rock mechanical models based on the mechanical properties and closure stress of the portion of shale rocks, and perform one or more fracture modeling simulations based on one or more treatment parameter values. Based on the one or more fracture modeling simulations, the system can generate a neural network model which predicts a fracture productivity indicator of an effective propped area (EPA) and/or an effective propped length (EPL), and calculate a return-on-fracturing-investment (ROFI) based on the EPA or EPL predicted by the neural network model.

Near real-time return-on-fracturing-investment optimization for fracturing shale and tight reservoirs

In accordance with some embodiments of the present disclosure, a geomechanical model of the stresses on an orthorhombic media for use during a subterranean operation is disclosed. The method includes retrieving a stiffness coefficient matrix for a formation to be fractured and generating a geomechanical model of the formation based on a set of natural fractures and an anisotropic behavior of the formation. The method additionally includes calculating a mechanical property of the formation based on the model and the stiffness coefficient matrix. The method further includes fracturing the formation with a fracturing fluid, a pressure of the fracturing fluid based on the mechanical property.

Geomechanical model of stresses on an orthorhombic media

In accordance with embodiments of the present disclosure, a simplified geomechanical model that considers the anisotropic (e.g., directional) properties of a formation and the presence of natural fractures in the formation is provided. A system and method may be designed according to the present disclosure to create a simplified geomechanical model of a horizontally laminated formation that includes pre-existing natural fractures. The simplified geomechanical model can be used to calculate the fracture closure pressure of the formation and to design a fracturing operation for injecting fracture fluid into the formation, thus improving the efficiency of a subterranean operation. The disclosed model may provide a more realistic model for fractured shales than an isotropic or vertically transverse isotropic (VTI) model. In addition, the disclosed model may be simpler to implement than a full orthorhombic model.

Simplified geomechanical model of stresses on an orthorhombic media

Apparatus and methods to evaluate a pipe structure taking buckling into account can be implemented in a variety of applications. Responses can be measured at a set of receivers of a tool in response to exciting the pipe structure with one or more electromagnetic signals transmitted from a set of transmitters of the tool. The set of receivers and the set of transmitters can be located within the pipe structure. Circuitry can be used to determine the presence of buckling of the pipe structure based on comparison of the measured responses with one or more forward models of the pipe structure. The pipe structure may be associated with a well site, such as, for example, a casing structure for a production well.

Inspection of pipes with buckling effects

System and methods for downhole fluid classification are provided. Measurements are obtained from one or more downhole sensors located along a current section of wellbore within a subsurface formation. The measurements obtained from the one or more downhole sensors are transformed into principal spectroscopy component (PSC) data. One or more fluid types are identified for the current section of the wellbore within the subsurface formation, based on the PSC data and a fluid classification model. The fluid classification model is refined for one or more subsequent sections of the wellbore within the subsurface formation, based at least partly on the one or more fluid types identified for the current section of the wellbore.

Automated downhole fluid classification using principal spectroscopy component data

Disclosed embodiments include systems and methods of correcting induction logging data for relative dip. Initial induction logging data is measured at a plurality of frequencies. One example embodiment includes displaying dip corrected data for a plurality of different relative dip angles, which may further be displayed with a qualitative indicator displayed over many depth samples for selecting or validating a correct relative dip angle. The data may be iteratively processed using an automated relative dip correction algorithm and analyzed by the user to obtain and apply the best relative dip correction angle to induction logging data. Once dip corrected, the induction logging data can be used with resistivity methodologies generally designed for instances where no dip is present in the formation under analysis.

Systems and methods for relative dip correction

A system and method for determining kerogen porosity of a formation for downhole operations is described herein. The method includes calculating a first formation characteristic and a second formation characteristic at a processor of an information handling system. The method further includes determining a kerogen porosity of the formation based, at least in part, on the first formation characteristic and the second formation characteristic. And the method also includes performing a downhole operation based, at least in part, on the determined kerogen porosity.

Dual porosity methodology for mineral volume calculations in source rock

In some embodiments, a method for transposition of logs onto a horizontal well path may include collecting vertical situational data from a plurality of depths of a vertical well in a geological formation and collecting horizontal situational data from a plurality of locations along the horizontal well path in the geological formation. The method further includes collecting geological data associated with the plurality of depths of the vertical well and generating pseudo-logs for the horizontal well path based on the plurality of depths and the associated geological data for the plurality of depths.

Transposition of logs onto horizontal wells

A method to minimize borehole effects upon a multi-component induction tool within a well and borehole with water-based mud includes measuring parameters of the reservoir with the induction tool to create an array of measured components. The method further includes comparing a measured component from the array of measured components with a corresponding model component from an array of model components for a reservoir model with known parameters and no borehole effects, and determining the parameters for the reservoir based upon the comparison of the measured component and the corresponding model component.

Method for minimization of borehole effects for multicomponent induction tool

A method for shale fracturing includes determining dynamic-elastic properties of a shale deposit in a geological formation. A training database is generated by three-dimensional fracture modeling. A neural network is generated in response to output results of the training database. The shale fracturing may then be performed based on the neural network.

Shale fracturing characterization and optimization using three-dimensional fracture modeling and neural network

In some embodiments, a method and apparatus, as well as an article, may operate to estimate a property of an earth formation by generating at least one shale model to represent an earth formation comprised of a non-zero percentage of shale. The shale model includes two curves to represent a relationship between a porosity parameter and a pulsed neutron measurement at two different corresponding percentages of gas saturation, respectively. A matrix model representing an earth formation with 0% shale is combined with one or more shale models to create a formation model. Measured pulsed neutron data is compared with the formation model to estimate a property of the earth formation. Additional apparatus, systems, and methods are disclosed.

Method to correct and pulsed neutron fan based interpretation for shale effects

Systems and methods for simultaneously correcting the effects of deviation and dispersion on sonic log measurements of deviated wells in laminated formations and validating the corrected sonic log measurements using rock physics cross-plots.

Correcting the effects of deviation and dispersion on sonic log measurements of deviated wells in laminated formations

A combination model combining a velocity regression method (V-reg) with the modified ANNIE model may be used to predict the stiffness coefficients, C, in a transversely isotropic medium without using the Stoneley wave velocity. The stiffness coefficients may be used to characterize the surrounding formation, which may be used in hydraulic fracture modeling, stage/perforation design, and well completion operations (e.g., perforating and fracturing operations).

Combination model for predicting stiffness coefficients absent Stoneley wave velocity data

Systems and methods for identifying formation layer boundaries on well log measurements using a second derivative of the last iteratively smoothed well log measurements and a fluctuation index to determine the extent of smoothing.

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Georgetown, TX, United States of America

John Andrew Quirein