Halliburton Energy Services, Inc.

Csw Therapeutics Ab

Christopher Lee Stokely

John Laureto Maida, Jr

Neal Gregory Skinner

Paul F Rodney

Leonardo De Oliveira Nunes

David Andrew Barfoot

Krishna M Ravi

Li Gao

Andreas Ellmauthaler

Satyan Gopal Bhongale

Lonnie Carl Helms

John L Maida

John Paul Bir Singh

Filip Ludwig Peters

Luke Christopher Downey

Etienne M Samson

Daniel Joshua Stark

Wolfgang Hartmut Nitsche

David E Sharp

Jamaal Brickhouse

Timothy R Tips

Andreas Ellamauthaler

Mena Nadum

John Laureto Maida

Leonardo De Nunes

An ultrasound therapy device for generating ultrasound therapy. The ultrasound therapy device includes a wearable structure, ultrasound transducer units, a tightening mechanism, a memory, and a processor. The wearable structure is securable to a user to transmit the ultrasound to a target therapy area of a user including at least one of a kidney region, a lung region, and a lower limb of the user. The ultrasound transducer units are attachable and repositionable in the wearable structure to generate and deliver the ultrasound to the target region. The ultrasound transducer units are arranged in an array. The array of ultrasound transducer units is mechanically moved within the wearable structure and is in contact with a material to facilitate penetration of ultrasound into the user's body.

Wearable and automated ultrasound therapy devices and methods

A system includes a controlled acoustic source. The system also includes distributed acoustic sensors along a conduit. The distributed acoustic sensors obtain acoustic signal measurements as a function of position along the conduit in response to at least one acoustic signal provided by the controlled acoustic source. The system also includes a processing unit that generates an acoustic activity plot or report based on the acoustic signal measurements. The acoustic activity plot or report is used to identify at least one acoustic impedance boundary anomaly as a function of position along the conduit.

Methods and systems employing a controlled acoustic source and distributed acoustic sensors to identify acoustic impedance boundary anomalies along a conduit

A flow assembly is deployed downhole in a casing for a cementing operation. The flow assembly has a spool with an optical cable. As cement is pumped downhole and through the flow assembly, a dart attached to the optical cable on the spool is dragged with the flow of cement. Cement flow is stopped based on signals along the optical cable that the dart is at a desired location downhole.

Fiber deployment system and communication

Systems and methods consistent with the present disclosure may position a cementing tool within a casing string of a wellbore. Such a system may include a fiber optic cable coupled to the cementing tool and may include a distributed temperature sensing (DTS) system interrogator positionable at a surface of the wellbore for transmitting an optical signal through the fiber optic cable such that a plurality of temperatures along the fiber optic cable may be identified. A reel may be used when dispensing the fiber optic cable from a first end of the fiber optic cable in response to a tension in the fiber optic cable as the cementing tool travels down the casing string behind a cement composition. A processor in communication with the DTS system may be configured to monitor the plurality of temperatures along the fiber optic cable while the cement composition cures.

Fiber optic distributed temperature sensing of annular cement curing using a cement plug deployment system

A method includes attaching a fiber optic cable to a cementing tool configured to attach to a cementing plug displace cement in a hydrocarbon well. The method can also include deploying the cementing tool in the hydrocarbon well to cause the cementing plug to begin releasing cement to form to displace cement to form a cement sheath in the hydrocarbon well. Additionally, the method can also include receiving, by a sensor receiver at a wellhead of the hydrocarbon well, a signal with cementing data as the cement sheath cures. Furthermore, the method can also include determining whether the cement sheath is curing properly. A system and a non-transitory computer readable medium are also provided.

Fiber optic sensing of wellbore leaks during cement curing using a cement plug deployment system

A system for cementing a wellbore having a casing string disposed in the wellbore is provided. The system includes a cement tool, a fiber optic cable, and a computing device. The cement tool is operable to be deployed down the wellbore through a casing string from a surface during cementing process of the wellbore. The cement tool includes a tool sensor. The fiber optic cable is coupled with the cement tool such that the fiber optic cable spans the wellbore from the cement tool to the surface. The fiber optic cable is communicatively coupled with the tool sensor. The computing device is communicatively coupled with the fiber optic cable and is operable to receive and process signals from the tool sensor via the fiber optic cable during the cementing process.

Method and system to conduct measurement while cementing

A sensor module can be used to make measurements during a single trip into and out of a wellbore in connection with a cement operation. The sensor module can include a detachment mechanism to detachably couple to a cement dart. The sensor module can also include a sensor to make measurements in a run-in-hole configuration prior to detaching from the cement dart and in a come-out-of-hole configuration subsequent to detaching from the cement dart in a wellbore. The sensor module can also include a transceiver to transmit the measurements to a processing device via a communication medium and to receive commands from the processing device via the communication medium.

Detachable sensor with fiber optics for cement plug

Determining a type of annular material in a wellbore comprises measuring an acoustic noise of one or more reference materials and thereby generating a corresponding one or more acoustic profiles, monitoring the annular material with an acoustic sensor positioned in the wellbore and thereby obtaining an acoustic response of the annular material, comparing the acoustic response with the one or more acoustic profiles using a processor communicably coupled to the acoustic sensor, and characterizing the annular material based on the comparison of the acoustic response and the one or more acoustic profiles.

Method and apparatus for identifying fluids behind casing

A plug may be deployed within a pipeline along with a fluid. The plug is coupled to a fiber optic line dispensed from fiber optic dispenser located outside or within the pipeline. The plug may transmit a signal via the fiber optic line that is indicative of the location of the plug within the pipeline. The signal may comprise light pulses associated with the traversal of a pipeline joint by the plug. The location may allow the plug to be reclaimed efficiently and economically should the plug become lodged within the pipeline. The plug may communicate other measurement information via the fiber optic line and this information may be used to adjust operational parameters associated with the pipeline.

Real-time plug tracking with fiber optics

A method includes obtaining distributed measurements of acoustic energy as a function of time and position downhole. The method also includes deriving acoustic activity values as a function of time and position from the one or more distributed measurements. The method also includes predicting fluid flow for a downhole perforation cluster as a function of time, wherein predicting fluid flow involves a flow prediction model that is a function of perforation cluster geometry, fluid characteristics, and at least one of the acoustic activity values. The method also includes storing or displaying the predicted fluid flow.

Flow prediction model that is a function of perforation cluster geometry, fluid characteristics, and acoustic activity

Methods for determining a density of a fluid are provided. The method can include passing the fluid through a conduit, measuring a vibration of the conduit by distributed acoustic sensing via a fiber optic cable coupled to the conduit, and generating a vibrational signal indicative of the measured vibration. At least a portion of the vibration of the conduit can be produced by the fluid passing therethrough. The method can also include measuring a temperature of the conduit and generating a temperature signal indicative of the temperature. The method can further include calculating the density of the fluid passing through the conduit by using the vibrational signal and the temperature signal.

Methods and systems for determining fluid density by distributed acoustic sensing

An example method includes providing source light to an optical fiber deployed in a downhole environment, receiving backscattered light from the optical fiber, and producing one or more optical interferometry signals from the backscattered light. The method also includes converting each of the one or more optical interferometry signals to an electrical signal and digitizing each electrical signal to obtain one or more digitized electrical signals. The method also includes deriving acoustic activity values as a function of time and position from the one or more digitized electrical signal. The method also includes applying at least some of the acoustic activity values to a flow prediction model to obtain a predicted fluid flow as a function of time, wherein the flow prediction model includes a proppant compensation value or factor. The method also includes storing or displaying the predicted fluid flow.

Methods and systems employing a flow prediction model based on acoustic activity and proppant compensation

The disclosed embodiments include methods and networks to determine a boundary of a cement mixture. In one embodiment, the method includes detecting first acoustic signals transmitted from at least one of a first plurality of acoustic tags that are mixed with cement slurry, where the cement slurry is deposited in a first section of a wellbore in an annulus between a casing and the first section of the wellbore. The method also includes determining a location of a first boundary of the cement slurry based on the first acoustic signals.

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Houston, TX, United States of America

Christopher Lee Stokely