Halliburton Energy Services, Inc.

Landmark Graphics Corporation

Li Gao

Michael Thomas Pelletier

David L Perkins

Christopher Michael Jones

Dingding Chen

Dale E Jamison

Mark Anton Proett

Daniel Joshua Stark

Robert S Atkinson

Krishna M Ravi

Xiangnan Ye

Stanley C Gianzero

Wei Zhang

Satyan Gopal Bhongale

James E Masino

Joni Polili Lie

Sami Abbas Eyuboglu

Paul F Rodney

Anthony Herman Van Zuilekom

John L Maida

Etienne M Samson

Christopher Lee Stokely

Tony Herman Van Zuilekom

Burkay Donderici

Michel Joseph LeBlanc

William Joseph Soltmann

Hua Xia

Lizheng Zhang

Jing Shen

Carl A Robbins

Arthur Cheng

Paravastu Badrinarayanan

Yenny Natali Martinez

Bipin Kumar Pillai

Paul Andrew Cooper

Jiaqi Xiao

Gireesh K Bhat

Faisal Farooq Shah

David Earl Ball

Nestor Rodriguez

Xinwei Lan

Thurairajasingam Rajasingam

Murali Krishna Thottempudi

Michael S Bittar

Neal Gregory Skinner

Ahmed Elsayed Fouda

Glenn Andrew Wilson

John Laureto Maida, Jr

Batakrishna Mandal

Darren George Gascooke

James Martin Price

Mark Windsor Roberson

Vimal Vinod Shah

Wallace R Gardner

Jeffrey Lee Moore

Thanh Thien Tran

Bruce H Storm, Jr

Scott Goodwin

Yao Ge

Andreas Ellmauthaler

Megan Renee Pearl

Walmy Cuello Jimenez

John P Singh

Wolfgang Hartmut Nitsche

Avinash Vinayak Taware

Ravi P Nanayakkara

Mukul M Agnihotri

Lucas Kurtis Fontenelle

Kris M Ravi

Jianxin Lu

Johanna Haggstrom

Charles Bartee

Luis Sanmartin

Arash Haghshenas

Lewis A Norman

Casey Giron

Jimmy W Anders

Sinan Sinanovic

Christopher Wayne Berry

Ramachandhran Balasubramanian

Alexis Garcia

Bob Engelman

Donald H Johnson

Chris Golla

Dinding Chen

Alexander Stewart

Patrick John Jonke

Rohin Naveena Chandran

Mahaly Randrianavony

Improved systematic inversion methodology applied to formation testing data interpretation with spherical, radial and/or cylindrical flow models is disclosed. A method of determining a flow line parameter includes determining a diverse set of flow models and selecting at least one flow model from the diverse set of flow models representative, at least in part, of a formation tester tool, at least one formation, at least one fluid, and at least one flow of the at least one fluid. The method further includes lowering the formation testing tool into the at least one formation to intersect with the formation at least one formation and sealing a probe of the formation tester placed in fluid communication with the at least one formation. The method further includes initiating flow from the at least one formation and utilizing the at least one selected flow model to predict the flow line parameter.

Method and apparatus for flow line parameter interpretation with diverse flow models

Improved systematic inversion methodology applied to formation testing data interpretation with spherical, radial and/or cylindrical flow models is disclosed. A method of determining a parameter of a formation of interest at a desired location comprises directing a formation tester to the desired location in the formation of interest and obtaining data from the desired location in the formation of interest. The obtained data relates to a first parameter at the desired location of the formation of interest. The obtained data is regressed to determine a second parameter at the desired location of the formation of interest. Regressing the obtained data comprises using a method selected from a group consisting of a deterministic approach, a probabilistic approach, and an evolutionary approach.

Method and apparatus for formation tester data interpretation with diverse flow models

A telemetry system is disclosed for use in a wellbore extending from the surface. The telemetry system includes fiber optic cable locatable in the wellbore, the fiber optic cable including at least one optical fiber. The telemetry system also includes a telemetry device operable to transmit an optical telemetry signal over the fiber optic cable. An optical detector operably connected to the optical fiber and includes a single-photon detector operable to receive the optical telemetry signal transmitted over the optical fiber.

System and method for arrayed telemetry using single-photon detectors

Gas bubble migration can be managed in liquids. In one example, a system can execute wellbore-simulation software to simulate changes in gas dissolution in a liquid over time. This may involve dividing the wellbore into segments spanning from the well surface to the downhole location, each segment spanning a respective depth increment between the well surface and the downhole location. Next, for each time, the system can determine a respective multiphase-flow regime associated with each segment of the plurality of segments based on a simulated pressure level, a simulated temperature, a simulated pipe eccentricity, and a simulated fluid velocity at the segment. The system can also determine how much of the gas is dissolved in the liquid at each segment based on the respective multiphase-flow regime at the segment. The system can display a graphical user interface representing the gas dissolution in the liquid over time.

Managing gas bubble migration in a downhole liquid

This disclosure presents a process for communications in a borehole containing a fluid or drilling mud, where a conventional mud pulser can be utilized to transmit data to a transducer. The transducer, or a communicatively coupled computing system, can perform pre-processing steps to correct the received data using an average of a moving time window of the received data, and then normalize the corrected data. The corrected data can then be utilized as inputs into a machine learning mud pulse recognition network where the data can be classified and an ideal or clean pulse waveform can be overlaid the corrected data. The overlay and the corrected data can be fed into a conventional decoder or decoded by the disclosed process. The decoded data can then be communicated to another system and used as inputs, such as to a well site controller to enable adjustments to well site operation parameters.

Machine learning mud pulse recognition networks

A downhole telemetry method and system are disclosed. In some embodiment, a method includes driving a pulser device based on an input data stream, wherein driving the pulser device includes generating modulated pressure pulses including modulated pulse shapes within a fluid telemetry medium. In some embodiments in which bi-modulation is utilized, the method further includes driving the pulser device including modulating pressure pulses including pulse position modulating pressure pulses.

Telemetry using pulse shape modulation

A formation test probe and a formation test system and method for implementing a self-drilling probe are disclosed. In some embodiments, a test probe includes a body having a channel therethrough to a frontside port, and further includes drill-in tubing disposed within the channel and having a front tip that is extensible from the frontside port. An exciter is disposed within the body in contact with the drill-in tubing and operably configured to induce resonant vibration in the drill-in tubing during a drill-in phase of a formation test cycle.

Formation test probe

Systems and methods are described herein. The method generally includes generating frequency responses of one or more sample fluids having known fluid properties, selecting an equivalent circuit model for modeling the frequency responses, the equivalent circuit model including one or more model elements, calculating an equivalent impedance of the equivalent circuit model, generating a correlation between the one or more model elements and the known fluid properties, measuring an impedance of a drilling fluid, and determining at least one property of the drilling fluid based on the correlation between the one or more model elements and the known fluid properties.

Application of electrochemical impedance spectroscopy in drilling fluid composition measurements

Systems and methods for determining the composition of a drilling fluid using electro-rheology.

Analyzing average specific gravity of solids in drilling fluids

A system is disclosed for optimizing mud-pulse communications in a wellbore. The system may include a mud pulser positionable in the wellbore and a surface detection system. The mud pulser can transmit a sequence of waveforms having various data rates to the surface detection system for synchronizing the mud pulser with the surface detection system. The surface detection system may receive the sequence of waveforms from the mud pulser and may determine one or more waveforms of the sequence of waveforms having amplitudes exceeding a predefined threshold. The surface detection system may then determine which of the one or more waveforms has a fastest data rate, and select the fastest data rate for use in subsequent communications with the mud pulser.

Data rate optimization and synchronization for mud-pulse telemetry in a wellbore

Systems and methods for measurement of the oil content in oil-based drilling may be provided in accordance with embodiments of the present disclosure. A method for measuring oil content of an oil-based drilling fluid may include providing a sample of the oil-based drilling fluid. The method may further include performing electro impedance spectroscopy on the sample by a process that comprises applying an alternating electric current to the sample and measuring a response of sample to obtain electro impedance spectroscopy measurements. The method may further include determining an estimate of the oil content of the sample based, at least partially on the electro impedance spectroscopy measurements.

Measuring the oil content in oil-based drilling fluids

A fluid is received into a sample tube. A processor causes an energy to be applied to the sample tube to induce vibration in the sample tube at a resonant frequency of the sample tube containing the fluid. The processor stops the supply of energy to the sample tube. The processor monitors an amplitude of the vibration of the sample tube as the amplitude of the vibrations diminish over a period of time. The processor uses the monitored amplitude to calculate an Rof the sample tube containing the fluid. The processor uses the calculated Rto calculate the viscosity of the fluid.

Viscosity sensor

Optical fiber having a graphene coating, a method to apply a graphene coating onto an optical fiber, and a fiber optic cable having a graphene coating are disclosed. A first carbon based coating is applied to an optical fiber along a longitudinal axis of the optical fiber. A laser beam is focused at the first carbon based coating. A first surface of the first carbon based coating is photothermally converted into a first layer of graphene.

Laser induced graphene coated optical fibers

The disclosed embodiments include downhole leak monitor systems, downhole leak monitors, and methods to monitor downhole leaks. In one embodiment, a downhole leak monitor system includes a plurality of downhole leak monitors (monitor), where each monitor is deployed along a casing of a wellbore. Each monitor is operable to detect at least one property of a fluid flow through an aperture of a barrier and to determine a location of the aperture. Each monitor is also operable to establish a connection with at least one other monitor, the connection being one of a plurality of connections, together which, communicatively connects the monitor to a top monitor. Each of the monitor is further operable to transmit data indicative of the at least one property of the fluid flow and the location of the aperture to the at least one other monitor.

Downhole leak monitor system

An acoustic receiver is provided. The acoustic receiver includes an optical vibrometer having an optical emitter and an optical receiver. The optical receiver is operable to emit an optical beam to a single point of reference on a conduit, and the optical receiver is operable to receive one or more reflections of the optical beam off of the single point of reference on the conduit, thereby detecting waves propagating through the conduit created by an acoustic transmitter. A processor is coupled with the optical emitter and the optical receiver. The processor is operable to: determine components of the waves created by the acoustic transmitter based on the one or more reflections of the optical beam; and determine a signal transmitted from the acoustic transmitter based on the components of the waves.

Acoustic telemetry system

Growing community of inventors

Katy, TX, United States of America

Li Gao