Schlumberger Technology Corporation

Halliburton Energy Services, Inc.

Westerngeco L.l.p.

Services Petroliers Schlumberger

Schlumberger Holdings Limited

Prad Research and Development Limited

Westerngeco Seismic Holdings Limited

Richard Timothy Coates

Douglas E Miller

Chung Lung Chang

Francois M Auzerais

Ruijia Wang

Jing Jin

Rod W Shampine

Tarek M Habashy

Arthur H Hartog

Philip F Sullivan

Dominic Joseph Brady

Peng Li

Nicholas N Bennett

Xiang Wu

Yao Ge

Iain Michael Cooper

Craig J Beasley

Dominique Guillot

Qingtao Sun

Benjamin Peter Jeffryes

Hiroaki Yamamoto

Dzevat Omeragic

John Mervyn Cook

Takeshi Endo

Colin Allan Wilson

Paul Simon Hammond

Benoit G Froelich

Paul Bolchover

Kristoffer Thomas Walker

Philip Christie

Jiajun Zhao

Ian Bradford

Jakob Brandt Utne Haldorsen

Kun Jiao

Henry Menkiti

Ian David Richard Bradford

Rodney Allen Marlow

Colin A Wilson

Yu Weng

Alan Schiemenz

Hannah Flath

Philip Andrew Felton Christie

Marcel Boucher

Denes Vigh

Alberto Malinverno

Scott W Leaney

Jean G Saint Germain

Brenda Sue Jonathan

David Edward Nichols

Darrell Coles

Steve Horne

Clara Castellanos Lopez

Cintia Lapilli

Eric Lavruit

Nobuyasu Hirabayasbi

Wei Huang

Dominque Guillot

William Li-Tien Wang

Zhen Xu

Phil F Sullivan

Dmitry Kulakov

Wei Dai

Dominic Brady

Methods, systems and devices are disclosed for controlling self-induced acoustic interference. In one embodiment, a first piezoelectric transducer to which a first excitation signal is applied, generates back side acoustic waves that are transmitted from a back side of the first piezoelectric transducer into a backing material layer. A second piezoelectric transducer coupled to a back side of the backing material layer generates a first calibration response to the back side acoustic waves. An interference signal profile is generated based, at least in part, on the first calibration response and may be used to filter interference signal components and/or to generate a control signal to be applied to the second piezoelectric transducer during measurement cycles.

Acoustic sensor self-induced interference control

Disclosed herein is a method for eccentricity correction. This method may dispose a downhole tool into a borehole. The downhole tool may comprise a measuring assembly that has at least one transducer, determining a beam pattern from the at least one transducer, determining a center of the measurement assembly in the borehole with the beam pattern, calculating a beam pattern factor with at least the beam pattern, calculating an angle factor with at least the beam pattern, calculating an eccentricity factor with at least the beam pattern factor and the angle factor, and creating an eccentricity corrected image with at least the eccentricity factor.

Downhole ultrasound image correction in oil based mud

An apparatus includes a mechanical wave source; a set of mechanical wave sensors in a borehole to provide subsurface wave measurements based on formation waves from the mechanical wave source, and a processor. The apparatus also includes a machine-readable medium having program code to acquire the subsurface wave measurements, select a first set of tool wave measurements based on the subsurface wave measurements, and generate a set of filtered subsurface wave measurements by filtering the subsurface wave measurements based on the first set of tool wave measurements. The program code also includes instructions to generate a time-domain semblance map based on the set of filtered subsurface wave measurements, wherein the time-domain semblance map includes an initial set of compression wave peaks, determine a selected qualified compression wave peak based on a semblance value in the time-domain semblance map, and determine a compression wave slowness based on the selected qualified compression wave peak.

Subsurface wave slowness prediction system

Disclosed is a system and method for calculating a formation shear-wave slowness. The system includes a borehole sonic logging tool and an information handling system. The borehole sonic logging tool may comprise a transmitter comprising one or more elements disposed at one or more radial distances from an axis of the borehole sonic logging tool and the transmitter is configured to transmit a first mode into a borehole. The sonic logging tool may further include one or more receivers disposed at a second radial distance from the axis of the borehole sonic logging tool and are configured to detect a second mode that one or more lobes than is a higher order than the first mode. A method may comprise broadcasting the first mode into the borehole, recording the second mode from the borehole with the one or more receivers, and calculating the formation shear-wave slowness from the second mode.

Extracting shear wave slowness from hexapole waves and octupole waves

To generate dispersion curves for acoustic waves in a radially layered system, a matrix M containing solutions to the wave equation subject to the boundary conditions of the system is constructed. The reciprocal condition number (RCN) of the matrix M is determined as a function of acoustic wave frequency and slowness. The local minima of the RCN in the frequency-slowness plane produces the dispersion curves corresponding to allowable acoustic modes in the system. A sensitivity analysis which identifies the dispersion curves dependent on a selected parameter. The dispersion curves independent of the perturbed parameters are eliminated by perturbing the modeling parameters and generating the RCN of the perturbed matrix M and then subtracting the RCN values of the unperturbed matrix M, leaving the dispersion curves that exhibit dependence on the selected parameter.

Acoustic dispersion curve identification based on reciprocal condition number

A logging-while-drilling (LWD) tool for use within a formation. The LWD tool may include a transmitter, a receiver, and an acoustic isolator. The transmitter may be operable to transmit an acoustic signal into the formation. The receiver may be operable to receive an acoustic response from the formation. The acoustic isolator may be positioned longitudinally between the transmitter and the receiver to reduce a transfer of acoustic energy between the transmitter and the receiver through the LWD tool. The acoustic isolator may include annular chambers formed in a body of the acoustic isolator and positioned along a longitudinal axis of the acoustic isolator.

Logging while drilling tool

A method for generating acoustic images corrected for distortions caused by attenuation of the ultrasonic signal by the mud may comprise disposing a downhole tool into a borehole, transmitting a pressure pulse from at least one transducer into the borehole, recording an echo with the at least one transducer, measuring a travel time, measuring an amplitude, determining a geometry of the borehole, determining a location of the downhole tool in the borehole, calculating an incident angle, mapping a mud attenuation, and correcting an image. A system for generating acoustic images corrected for distortions caused by attenuation of the ultrasonic signal by the mud comprising a downhole tool that may comprise a measuring assembly, wherein the measuring assembly comprises at least one transducer and wherein the at least one transducer is configured to emit a pressure pulse and record an echo. The system may further comprise an information handling system.

Acoustic waves are obtained from an acoustic logging tool within a borehole passing through a formation. Signal properties in a time domain, frequency domain, or both are determined based on the obtained acoustic waves. A machine learning analysis is used to determine formation slowness based on the determined signal properties and a downhole operational parameter is adjusted based on the determined formation slowness.

Methods and systems for processing slowness values from borehole sonic data

A method may comprise recording a first reflected waveform with a first transducer to form a first data set from a first excitation, recording a second reflected waveform with a second transducer to form a second data set from a second excitation, estimating a first sensitivity correction factor for the first data set, applying the first sensitivity correction factor to at least a portion of the first data set to form a first sensitivity corrected data set. The method may further comprise estimating a second sensitivity correction factor for the second data set, applying the second sensitivity correction factor to at least a portion of the second data set to form a second sensitivity corrected data set, stacking the first sensitivity corrected data set amplitudes and forming a first image, stacking the second sensitivity corrected data set amplitudes and forming a second image, and comparing the images.

Dynamic transducer normalization

A method and system for reducing transducer ringing. The method may comprise identifying a first set of waveforms and a second set of waveforms from recorded waveforms taken by a transducer, estimating an invariant component for each waveform in the first set of waveforms, and subtracting the invariant component from the second set of waveforms. The system may comprise a downhole tool. The downhole tool may comprise at least one transducer and wherein the at least one transducer is configured to emit an excitation and record a plurality of waveforms. The system may further comprise an information handling system configured to identify a first set of waveforms and a second set of waveforms from the plurality of waveforms from the at least one transducer, estimate an invariant component for each waveform in the first set of waveforms, and subtract the invariant component from the second set of waveforms.

Transducer ringing

Disclosed herein are implementations of various technologies for a method for seismic data processing. The method may receive seismic data for a region of interest. The seismic data may be acquired in a seismic survey. The method may determine an exclusion criterion. The exclusion criterion may provide rules for selecting shot points in the acquired seismic data. The method may determine sparse seismic data using statistical sampling based on the exclusion criterion and the acquired seismic data. The method may determine simulated seismic data based on the earth model and shot points corresponding to the sparse seismic data. The method may determine an objective function that represents a mismatch between the sparse seismic data and the simulated seismic data. The method may update the earth model using the objective function.

Seismic data processing

Described herein are implementations of various technologies for a method for seismic data processing. The method may receive seismic data for a region of interest. The seismic data may be acquired in a seismic survey. The method may determine sparse seismic data by selecting shot points in the acquired seismic data using statistical sampling. The method may determine simulated seismic data based on an earth model for the region of interest, a reflection model for the region of interest, and the selected shot points. The method may determine an objective function that represents a mismatch between the sparse seismic data and the simulated seismic data. The method may update the reflection model using the objective function.

A method for processing seismic data includes obtaining a velocity model, determining a critical angle for an interface represented in the velocity model based on a ratio between velocity of the seismic wave on first and second sides of the interface, determining an orientation of a normal vector extending normal to a location of the interface, determining an orientation of an arrival direction vector of a wavefield at the location of the interface, calculating an angle between the normal vector and the arrival direction vector, determining that the angle between the normal vector and the arrival direction vector is greater than the critical angle at the location, and attenuating the wavefield associated with the location in response to determining that the angle between the normal vector and the arrival direction vector is greater than the critical angle at the location.

Post-critical reflection muting in seismic migration

A method comprising for deghosting seismic data is disclosed. The method includes the steps of acquiring seismic data by conducting a survey of a subsurface area of interest wherein the seismic data includes ghost data and estimating a time-varying wave height above the subsurface area of interest during at least a portion of the survey, wherein the estimation of the wave height is based at least in part on a remote measurement of the wave height during the survey. The estimated time-varying wave height is used to characterize the ghost data and deghost the seismic data based at least in part on the characterized ghost data.

Method and apparatus for determining rough sea topography during a seismic survey

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Katy, TX, United States of America

Richard Timothy Coates