Halliburton Energy Services, Inc.

Hsu-Hsiang Wu

Burkay Donderici

YiJing Fan

Li Pan

Michael S Bittar

Jin Ma

Akram Ahmadi Kalateh Ahmad

Weixin Dong

Yi Jing Fan

Christopher A Golla

Shanjun Li

Matthew Chase Griffing

Rencheng Song

Clint Paul Lozinsky

Luis Emilio San Martin

Glenn Andrew Wilson

Joseph Keith Young

Paul F Rodney

Baris Guner

Yumei Tang

Brian Roberson

Jason Daniel Dykstra

Ilker R Capoglu

Roland Edward Chemali

Yuzhen Xue

Dagang Wu

Randal Thomas Beste

Anand Prakash

Jesse Kevin Hensarling

Imran Sharif Vehra

Svetozar Dimitrov Simeonov

Wei-Bin Ewe

Wenquan Li

Faisal Farooq Shah

Paul Chin Ling Chang

Malcolm Upshall

Joseph D Burke

Robert Wayne Pennison

Randy Beste

Ting Yan

Paul Chin Chang

Robert W Pennison

Systems and methods for smoothing a resistivity log are disclosed. An azimuthal resistivity tool measures azimuthal impedances at multiple azimuthal angles around a wellbore axis at each depth. It is determined whether the drill string was in a drilling mode or a sliding mode at the depth. If the drill string was in the drilling mode, a co-axial component and a lateral component are determined based in part on the azimuthal impedances associated with the depth and the lateral component is stored. If the drill string was in the sliding mode, a second co-axial component is determined based in part on at least one of the plurality of azimuthal impedances and a previously stored lateral component. The resistivity log is plotted from resistivities determined from the first and second co-axial components at each depth.

Resistivity logging in sliding mode

A method comprises obtaining measurement data of a subsurface formation while drilling a wellbore in the subsurface formation. The method comprises generating a horizontal resistivity model of the subsurface formation at respective depths along the wellbore based on the measurement data. The method comprises generating a vertical resistivity model of the subsurface formation at the respective depths along the wellbore based on the measurement data. The method comprises generating an effective resistivity at the respective depths along the wellbore based on the horizontal resistivity model and the vertical resistivity model to indicate a formation resistivity in each direction of the wellbore. The method comprises performing a drilling operation based on the effective resistivity.

Effective resistivity models for geosteering decisions

A system and a method for a look-ahead drill bit. The system may comprise an ultra-deep transmitter operable to transmit a low frequency signal into a formation, a shallow tool operable to transmit a high frequency signal into the formation, at least one ultra-deep receiver operable to record a reflected low frequency signal, and at least one pair of collocated receivers, wherein the at least one pair of collocated receivers are operable to record a reflected high frequency signal. A method may comprise transmitting a high frequency signal from the shallow tool into the formation, transmitting a low frequency signal from the ultra-deep transmitter into the formation, evaluating the reflected high frequency signal and the reflected low frequency signal on an information handling system with a look-ahead inversion, and steering the bottom hole assembly in the formation based on the subterranean formation property.

Look-ahead resistivity configuration

System and methods for geosteering inversion are provided. Downhole tool responses are predicted for different points along a planned path of a wellbore during a downhole operation, based on each of a plurality of inversion models. Measurements of the downhole tool's actual responses are obtained as the wellbore is drilled over the different points during a current stage of the operation. The inversion models are clustered based on a comparison between the actual and predicted tool responses and a randomly selected centroid for each cluster. The inversion models are re-clustered using an average inversion model determined for each cluster as the centroid for that cluster. At least one of the re-m clustered inversion models is used to perform inversion for one or more subsequent stages of the downhole operation along the planned wellbore path. The planned wellbore path is adjusted for the subsequent stage(s) of the downhole operation.

Iterative clustering for geosteering inversion

A system can calibrate inconsistencies in a wellbore tool. The system can receive a first set of measurements and a second set of measurements with respect to different electromagnetic antennas. The system can decouple a first multi-components tensor corresponding to the first set of measurements and a second multi-components tensor corresponding to the second set of measurements. The system can determine, using the decoupled first and second multi-components tensors, a scaling factor. The system can apply the scaling factor to a raw measurement received with respect to an electromagnetic antenna of the wellbore tool positioned in a wellbore to decouple a third multi-components tensor or to decoupled components of a fourth multi-components tensor for controlling a wellbore operation.

Scaling factor for calibrating antennas of a wellbore tool

A system and a method for evaluating a subterranean earth formation include a logging tool locatable in a wellbore dispose in the formation. The logging tool may include a transmitter antenna and a single receiver antenna. The transmitter antenna is configured to transmit a first electromagnetic signal into the subterranean earth formation. The system further includes a processor and a non-transitory memory device. The memory device includes instructions that cause the processor to control a current and a voltage sourced to the transmitter antenna, receive, via the single receiver antenna, a second electromagnetic signal emitted by the subterranean earth formation in response to receiving the first electromagnetic signal, and determine a resistivity of the subterranean earth formation based on the second electromagnetic signal.

Resistivity determination from one transmitter and one receiver antennas

Some aspects relate to techniques for calibrating a logging tool. In some implementations, the logging tool may estimate certain unknown properties of a signal based on distances between transmitters and receivers of the logging tool and based on frequencies used by the transmitters and receivers. The logging tool may estimate the unknown properties by interpolating values into a mathematical function related to the above-noted distances and frequencies. After estimating the unknown properties, the logging tool may be deployed into the wellbore, where it may use the estimated properties to process signals received through a subsurface formation.

Cross-component response interpolation for coaxially oriented antennas in an electromagnetic tool

Systems and methods of the present disclosure relate to calibration of resistivity logging tool. A method to calibrate a resistivity logging tool comprises disposing the resistivity logging tool into a formation; acquiring a signal at each logging point with the resistivity logging tool; assuming a formation model for a first set of continuous logging points in the formation; inverting all of the signals for unknown model parameters of the formation model, wherein the formation model is the same for all of the continuous logging points in the first set; assigning at least one calibration coefficient to each type of signal, wherein the calibration coefficients are the same for the first set; and building an unknown vector that includes the unknown model parameters and the calibration coefficients, to calibrate the resistivity logging tool.

Accurate and cost-effective inversion-based auto calibration methods for resistivity logging tools

Borehole images can be corrected using machine-learning models. For example, a system can train a machine-learning model based on a training dataset. The training dataset can include a first set of borehole images correlated to a second set of borehole images, where the second set of borehole images are less precise versions of the first set of borehole images. The system can then execute the trained machine-learning model in relation to an input borehole image to receive a corrected borehole image as output from the trained machine-learning model. The corrected borehole image can be a visually corrected version of the input borehole image. The system may then perform one or more operations based on the corrected borehole image, such as generating a graphical user interface that includes the corrected borehole image for display on a display device.

Correcting borehole images using machine-learning models

A system and method for evaluating a subterranean formation includes a logging tool that includes transmitter and receiver antennae. The transmitter antenna transmits a first electromagnetic signal into the formation at a plurality of depths. The receiver antenna receives a plurality of second electromagnetic signals emitted by the formation in response to the first signal. The system and method also include a processor configured to calculate resistivity values for the second signals, calculate solutions to an inversion algorithm of the formation, filter the solutions into a plurality of convergent solutions, pixilate the convergent solutions into pixilated solutions, calculate ensemble statistics for the pixilated solutions, calculate a difference in resistivity value between successive pixels, identify presumptive layer boundaries based on the differences in resistivity values, calculate composite resistivity statistics from the pixilated solutions based on the presumptive layer boundaries and the ensemble statistics, and generate a formation model.

System and methods for evaluating a formation using pixelated solutions of formation data

A method and system for identifying a blind spot in one or more decoupled measurements. The method may comprise disposing an electromagnetic well measurement system into a wellbore. The electromagnetic well measurement system comprise an electromagnetic transmitter and a plurality of electromagnetic receivers. The method may further comprise transmitting electromagnetic fields into a formation with the electromagnetic transmitter, measuring the electromagnetic fields with the plurality of electromagnetic receivers as one or more measurements at one or more depths in the wellbore, decoupling the one or more measurements to form decoupled measurements, identifying if a blind spot is in the decoupled measurements, and performing an inversion with the decoupled measurements.

Compound signal for logging while drilling resistivity inversion

A method includes detecting, via first and second receivers of a tool that are oriented at a first and a third tilt angle, respectively, a first and second measurement of a first signal transmitted by a transmitter of the tool that is oriented at a second tilt angle into a substantially non-conductive material. The method includes determining, based on the first and second measurements, a first tensor and conveying the tool into a first wellbore formed in a subsurface formation. The method includes detecting, via the first receiver and the second receiver, a third and fourth measurement, respectively, of a second signal transmitted by the transmitter and determining, based on the third and fourth measurements, a second tensor and determining a third tensor (having values independent of the first, second, and third tilt angles) based on a relationship between the first and second tensors.

Electromagnetic tool calibration for tilted antennas with undetermined orientation angles

Certain aspects of the present disclosure relate to calibrating a formation signal for a mixed set measurement device. A first air-hang response of a first measurement device for a tubular string associated with a drilling operation can be measured. A second air-hang response of a second measurement device for the tubular string associated with the drilling operation can be measured. The first air-hang response and the second air-hang response can be used to determine a mixed air-hang response of the mixed set measurement device. The mixed air-hang response can be used to calibrate a formation signal for the mixed set measurement device.

Mixed air-hang response for correcting a formation signal of a mixed set measuring device

This disclosure presents an apparatus and system for lowering the cost of implementing a downhole sensor system using attachable collars. In some aspects, the attachable collar includes a transmitter component, while supporting electronics are included with a main collar, thereby reducing the cost of the attachable collar. The supporting electronics can send a transmission signal, a control signal, a synchronization clock signal, a selected transmission frequency, a sensor orientation and selection, and other instructions to the transmitter in the attachable collar. The receiver in the main collar can receive the output, as reflected by the subterranean formation, and transform the output to subterranean formation evaluation measurements. The measurements can be communicated to other systems. In some aspects, the attachable collar can include the receiver and the main collar can include the transmitter. In some aspects, additional attachable collars can be included on the drill string to increase the transmitter-receiver spacing.

Minimal electronic sensor collars

A method and system for determining a position of a second production wellbore. The method may comprise inducing a first current into a first conductive member with a first source, emitting a first magnetic field generated by the first current from the first conductive member into a formation, inducing a second current into a second conductive member with a second source, emitting a second magnetic field generated by the second current from the second conductive member into the formation, disposing an electromagnetic sensor system into the second production wellbore, recording the first magnetic field with the at least one sensor from the formation, and recording the second magnetic field with the at least one sensor from the formation. The system may comprise a first source, an electromagnetic sensor system, at least one sensor and an information handling system configured to determine the position of the second production wellbore.

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Sugar Land, TX, United States of America

Hsu-Hsiang Wu