Halliburton Energy Services, Inc.

William Marsh Rice University

University of Texas System

Daniel Joshua Stark

John L Maida

Satyan Gopal Bhongale

Li Gao

Dale E Jamison

David Andrew Barfoot

Christopher Michael Jones

Bin Dai

Michel Joseph LeBlanc

John Laureto Maida, Jr

Etienne M Samson

Renata Pasqualini

Andrew David Vos

Wadih Arap

Glauco Souza

Aaron Michael Fisher

Thomas Charles Killian

Robert M Raphael

James Martin Price

Denise Nicole Benoit

Tirumani N Swaminathan

Yenny Natali Martinez

Jian Li

Baidurja Ray

Adam Harold Martin

Oluwatosin Ogundare

Gireesh K Bhat

Jeremy C Nicholson

Brian Alan Evans

Xinwei Lan

Casey Giron

Sergei Parsegov

Tirumani Swaminathan

Paul F Rodney

Stanley Vernon Stephenson

Krishna M Ravi

Glenn Andrew Wilson

Wei Zhang

William Cecil Pearl, Jr

James Marshall Barker

Ilker R Capoglu

Yao Ge

Andreas Ellmauthaler

Sean Gregory Thomas

Boguslaw Wiecek

Adan Hernandez Herrera

Philippe Quero

Christopher Lee Stokely

Ira Jeffrey Bush

Radovan Rolovic

David Bennett

Alexander Simon Chretien

Hazim H Abass

Mateusz Michal Dyngosz

Terry Bickley

David Yan Lap Wong

Marek Kozikowski

Claudio Olmi

Roshan Joy Jacob

Neerja Aggarwal

Aurel Adrian Popoviciu

Lori A Newhouse

Ramalakshmi Somaskandan

Alexis Garcia

Allan Silva Freitas

Srividhya Veeravalli Murali

Patrick John Jonke

Mark McGouldrick

David B Bennett

John Laureto Maida

Jeremy Coss Nicholson

Glauco R Souza

Analyzing solid components in the return line of a borehole can be accomplished by implementing a bar or disc in the return line. As solid components pass by, they will generate an acoustic wave on impact. In another aspect, solid components can be directed to a shaker system where the solid components will impact a soundboard. The acoustic waves can be captured, such as by a microphone or transducer. The acoustic waves can be processed and transformed into acoustic data. A machine learning system can use previously trained models to determine the solid component parameters using the acoustic data. The parameters can include the size, shape, composition, density, softness, wettability, and other parameters of the solid components. These parameters can then be used as inputs to users or other borehole systems, such as a well site controller to improve drilling operations or to identify the need to implement corrective actions.

Analyzing drill cuttings using acoustic analysis

Provided is a flowback system and method. The flowback system, in one aspect, include a tank, a transfer pump, a low-pressure vent line coupled between a vent of the tank and a first flare tip, and a high-pressure gaseous hydrocarbon line coupled to a second flare tip. In accordance with yet one other aspect, the flowback system includes a control system including a sensor, a valve and a valve controller coupled to the valve, the valve of the control system coupled between the low-pressure vent line and the high-pressure gaseous hydrocarbon line, the control system configured to sense an unsafe system event and actuate the valve to supply high-pressure gaseous hydrocarbons from the high-pressure gaseous hydrocarbon line to the low-pressure vent line.

Systems and methods to prevent explosions in a tank using automated gas harvesting and purge safety devices

A system is provided including a coiled tubing reel apparatus including a reel drum for storing a coiled tubing string spooled on the reel drum and a hydraulic reel drive motor that controls rotation of the reel drum. The system further includes a reel controller that determines an estimated reel back tension for a portion of the coiled tubing string between the reel apparatus and the injector based on a set of parameters related to a coiled tubing operation. The reel controller determines a target reel back tension to be applied to the portion of the coiled tubing string by adjusting the estimated reel back tension based on a historical job dataset. The reel controller then determines and sets a target hydraulic pressure of the reel drive motor to achieve the target reel back tension in the portion of the coiled tubing string.

Reel control in a coiled tubing system

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

A distributed control system can be used to implement failover capabilities for control units that control well equipment during a well operation. For example, a system can include first well equipment that performs a first physical task and second well equipment that performs a second physical task different from the first physical task. Additionally, the system can include a distributed control system with a first control unit coupled to the first well equipment and a second control unit coupled to the second well equipment. Both control units may include a first control module and a second control module for automatically controlling the first physical task and the second physical task, respectively. The distributed control system can detect a failure of the second control unit and initiate a failover process in which the first control unit takes over control of the second physical task by enabling the second control module.

Distributed control system with failover capabilities for physical well equipment

Distributed artificial intelligence (AI) can be used to monitor a wellbore operation in some examples described herein. In one such example, physical equipment can be positioned at a surface of a wellsite to support a drilling operation at the wellsite. Each piece of physical equipment may include a sensor module, a processor communicatively coupled to the sensor module, and a memory. The memory can include an AI module configured to determine a condition associated with the equipment by analyzing sensor data from the sensor module using one or more machine-learning models. The memory additionally can include a warning module for causing the processor to output a warning notification based on the condition. The memory further can include a communications module for causing the processor to transmit a communication indicating the condition to a destination via a network. The communication may be different from the warning notification.

Monitoring a wellbore operation using distributed artificial intelligence

Aspects of the subject technology relate to systems and methods for optimizing multi-unit pumping operations at a well site. Systems and methods are provided for receiving sensor data from a hydraulic fracturing fleet equipment at an equipment system, designating an event as being flagged based on the sensor data from the hydraulic fracturing fleet equipment, determining a physical action based on the flagged event and a priority list of actions, and providing instructions to a first pump of the hydraulic fracturing fleet equipment to perform the physical action based on the flagged event and the priority list of actions.

Distributed diagnostics and control of a multi-unit pumping operation

A mobile robot is disclosed herein. The mobile robot may include a frame, a propulsion module, a navigation module designed to navigate the mobile robot along a target pathway, and a computational module. The mobile robot may obtain a composition reading of the drilling fluid and a pressure reading of the drilling fluid. The robot may determine, using the computational module, an additive to add to a drilling fluid reservoir based on the composition reading and the pressure reading. The mobile robot may then retrieve the additive from an inventory and deposit the additive into the drilling fluid reservoir.

Mobile robots for managing drilling operations

A system is provided including at least one pump for pumping a fluid into a wellbore, a pressure sensor provided at a wellhead of the wellbore for measuring a backpressure of the fluid being pumped into the wellbore, and a diagnostic manager. The diagnostic manager obtains pressure data associated with a pressure signal from the pressure sensor, wherein the pressure data includes pressure measurements of the fluid over a selected time period. The diagnostic manager converts, based on the pressure data, at least a portion of the pressure signal into frequency domain. The diagnostic manager detects a change in frequency of the pressure signal in the Fourier spectrum and determines that a fault associated with the wellbore has occurred based on the changed frequency of the pressure signal.

Detection of wellbore faults based on surface pressure of fluids pumped into the wellbore

Construction and use of an instrument test fixture for capturing performance data for stimulation or fracturing treatments. The test fixture includes a target material, such as concrete, which includes embedded sensors surrounding a casing. An energetic stimulation treatment, such as a dynamic pulse fracturing technique, is applied through the casing to the target material to simulate a treatment that would be performed in a wellbore. During application of the treatment, the sensors capture measurements which are recorded for analysis by a data collection system. The sensors allow for the measurement of key performance indicators including static and dynamic pressure, generated temperature, and resulting strain energy. The captured data can be analyzed and used to design and optimize stimulation treatments for field applications.

Instrumented fracturing target for data capture of simulated well

A dissolvable connector allows a wireline or similar conveyance to be detached from a downhole tool or device based on conditions in a downhole environment instead of an external action, such as application of tension or an electrical pulse. The dissolvable connector can be strategically positioned to allow retrieval of expensive tools and equipment that are located above the connector. A protective sheath may be provided around the dissolvable connector that opens or unsheathes based on conditions in the downhole environment (e.g., pressure, temperature), a telemetry signal (e.g., from the surface or from a tool string), or tension, to provide greater control over the timing of the release of the dissolvable connector. Such a dissolvable connector allows the device to be detached from the conveyance without the need for wire-cutting operations or weak-point breaking operations.

Dissolvable connector for downhole application

An integrated computing element for an optical computing device includes a flexible optical substrate. The integrated computing element also includes at least one optical thin film deposited on a first surface of the flexible optical substrate. The at least one optical thin film is configured to selectively pass fractions of electromagnetic radiation at different wavelengths.

Flexible integrated computational elements for optical analysis

A downhole tool is positioned in a borehole of a geological formation at a given depth. A formation property is determined at the given depth. The positioning and determining is repeated to form data points of a data set indicative of formation properties at various depths in the borehole. One or more outlier data points is removed from the data set based on first gradients to form an updated data set. One or more properties associated with a reservoir compartment are determined based on second respective gradients associated with the updated data set.

Determining pressure measurement locations, fluid type, location of fluid contacts, and sampling locations in one or more reservoir compartments of a geological formation

A method and system for in-sit calibration of a gravimeter. A method may comprise disposing a downhole tool in a borehole, wherein the downhole tool comprises the gravimeter attached to a linear actuator, recording a first set of measurements with the gravimeter while the linear actuator is stationary, activating the linear actuator, recording a second set of measurements with the gravimeter, and calibrating the gravimeter based on the first and second set of recorded measurements. A system may comprise a downhole tool, a conveyance, and an information handling system. The downhole tool may further comprise a hanger, a sonde, connected to the hanger, a linear actuator, connected to the hanger, and a shaft, connected to the linear actuator. The downhole tool may further comprise a linkage, connected to the shaft, a package, connected to the linkage, and a gravimeter, disposed in the package.

In-situ calibration of borehole gravimeters

A system is provided that includes a dart, a pressure sensor, and a controller communicatively coupled with the sensor. The dart is disposed in a fluidic channel. The dart has a main body and a flange extending from the main body and has a diameter greater than or equal to a diameter of the fluidic channel. When the dart translates within the fluidic channel and passes a location of a variation in the fluidic channel, the flange creates a pressure pulse. The pressure sensor measures the pressure pulse within the fluidic channel created by the dart. The controller determines the location of the variation based on the measured pressure pulse.

Method and system to determine variations in a fluidic channel

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Houston, TX, United States of America

Daniel Joshua Stark