Halliburton Energy Services, Inc.

Welldynamics, B.v.

Weatherford/lamb, Inc.

Other

Weatherford Technology Holdings, LLC

Welldynamics, Inc.

John Laureto Maida, Jr

Wolfgang Hartmut Nitsche

Neal Gregory Skinner

Etienne M Samson

Michel Joseph LeBlanc

Christopher Lee Stokely

Paul David Ringgenberg

David Andrew Barfoot

David O Johnson

Paul F Rodney

Mikko K Jaaskelainen

Glenn Andrew Wilson

Andreas Ellmauthaler

Satyan Gopal Bhongale

Christopher Michael Jones

Krishna M Ravi

Daniel Joshua Stark

Eric James Davis

Luke Christopher Downey

Michael Thomas Pelletier

Alan D Kersey

Bin Dai

Lonnie Carl Helms

John Paul Bir Singh

James H Dudley

Deepak Varshneya

Sudhir Kumar Gupta

Ronald L Spross

Yenny Natali Martinez

John Luscombe

Ramon Hernandez Marti

Jose R Sierra

Casey Giron

Arabinda Misra

Christopher Lee Stokley

Michael Linley Fripp

Li Gao

Thomas Donovan Welton

James Martin Price

Timothy Rather Tips

Larry A Jeffers

Ian Bradford Mitchell

Philippe Quero

Ira Jeffrey Bush

Espen S Johansen

Bob A Hardage

Rory Dennis Daussin

Jian Li

Kwang Il Suh

Kris M Ravi

Zbigniew Sobolewski

Michel LeBLANC

Michael Konopczynski

Michel J Leblanc

William John Hunter

Richard M Wilde

Christopher W Mayeu

Jamaal Brickhouse

Ramachandhran Balasubramanian

Douglas Mark Knight

A fiber optic sensing (FOS) system may include a Brillouin Optical Time Domain Analyzer (BOTDA) unit, a first fiber optical cable optically connected to the BOTDA interrogator unit at a first end, and an optical feedthrough system (OFS) optically connected the first fiber optical cable at a second end of the first fiber optical cable. The FOS system may further comprise a fiber optic cable forming a loop within a wellbore that is optically connected to the first fiber optical cable at the OFS and a second fiber optical cable optically connected to the loop at the OFS and wherein the second fiber optical cable is optically connected to the BOTDA interrogator unit.

Multi-fiber sensing topology for subsea wells

A cable comprises a protective jacket and a plurality of conductor bundles symmetrically arranged within the protective jacket. The cable comprises optical fibers arranged within the protective jacket relative to the plurality of conductor bundles such that an orthogonal mode electrical field symmetry for the plurality of conductor bundles is retained.

Hybrid electro-optic wireline cable

A distributed acoustic system (DAS) may include an interrogator that includes two or more lasers, a pulser module disposed after and connected to each of the two or more lasers, a wavelength division multiplexer (WDM), wherein each of the pulser modules are connected to the WDM as inputs, and a downhole fiber attached to the WDM as an output and wherein the downhole fiber includes at least one sensing fiber. A method for increasing a sampling frequency may include identifying a length of a downhole fiber connected to an interrogator, generating and launching a light pulse from each of the two or more lasers the pulser module, and delaying an output from the pulser module into the downhole fiber by seconds, where k is a pulse repetition interval of the pulser module and N is equal to the two or more lasers.

Topside interrogation using multiple lasers for distributed acoustic sensing of subsea wells

Aspects of the subject technology relate to systems and methods for determining positions of cementing plugs during a cementing process. Systems and methods are provided for determining a length of an optical fiber line deployed into a wellbore for a cementing process, measuring signal intensity data as a function of distance from the optical fiber line, the optical fiber line being attached to a lower cementing plug and an upper cementing plug, the upper cementing plug being attached to the optical fiber line by an attenuation assembly, generating signal intensity profiles based on the signal intensity data as a function of a round trip delay of a light signal in the optical fiber line, and determining positions of the lower cementing plug and the upper cementing plug based on the signal intensity profiles of the optical fiber line.

Tracking cementing plug position during cementing operations

A system can calculate estimated strain data for a fracture in a geological formation at each of a plurality of selected locations detectable by a strain measurement device. The system can receive real strain data from the strain measurement device for the geological formation. The system can perform an inversion to determine a probable distribution of fluid volume and hydraulic fracture orientation in the geological formation based on the estimated strain data and real strain data. The system can determine adjustments for a fracturing operation based on the inversion.

Determining fluid distribution and hydraulic fracture orientation in a geological formation

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

A method for determining when to change a lubricating fluid flowing within an apparatus includes monitoring the lubricating fluid flowing within the apparatus by passing radiation through the lubricating fluid from a radiation source. The lubricating fluid is analyzed for a presence of particles in the lubricating fluid based on the radiation passing through the lubricating fluid. A concentration of the particles in the lubricating fluid is determined when the presence of particles is detected. An alert to change the lubricating fluid is generated when the concentration of particles in the lubricating fluid exceeds a threshold.

Determining timing for lubricating fluid change

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 can calculate estimated strain data for a fracture in a geological formation at each of a plurality of selected locations detectable by a strain measurement device. The system can receive real strain data from the strain measurement device for the geological formation. The system can perform a linear inversion to determine a probable distribution of fluid volume and hydraulic fracture orientation in the geological formation based on the estimated strain data and real strain data. The system can determine adjustments for a fracturing operation based on the linear inversion.

A system includes an optical fiber integrated into a conveyance subsystem that is positionable downhole in a wellbore. The system also includes a backscattering sensor system positionable to monitor temperature and optical fiber strain along the optical fiber using backscattered light signals received from the optical fiber. Further, the system includes a fiber optic rotary joint positionable to optically couple the optical fiber with the backscattering sensor system to provide an optical path for the backscattered light signals to reach the backscattering sensor system.

Wellbore distributed sensing using fiber optic rotary joint

A system for conducting real-time chemical analysis of deposits is provided. The system includes an electromagnetic radiation source positioned on a downhole tool that emits electromagnetic radiation to a surrounding downhole environment within a field of view of interest. The system also includes a multivariate optical element positioned on the downhole tool that has optical filters configured to receive reflected radiation from the field of view of interest and generate respective filtered radiation signals. Each of the optical filters has a different transmission function that corresponds to a respective chemical species of interest. The system also includes an image sensor positioned on the downhole tool that detects each of the respective filtered radiation signals from the multivariate optical element. The image sensor provides image information of the field of view of interest that indicates a presence of at least one chemical species of interest located in the surrounding downhole environment.

System and method to conduct real-time chemical analysis of deposits

A hybrid electro-optic (EO) wireline cable includes optical fibers strategically placed within to allow acoustic sensing methods as well as provide power and electrical telemetry. The hybrid EO wireline cable contains optical fibers in the interstices among symmetrically arranged electrical wire bundles to allow a hybrid EO cable to be concurrently used for electrical telemetry and optical fiber sensing without interference in a wellbore environment. This hybrid EO cable maintains electric and magnetic field symmetry which allows an optimal electrical signaling rate through orthogonal propagation modes. By placing optical fibers symmetrically inside the interstitial spaces between electrical wire bundles, the cable maintains its optimal signaling rate and avoids the mechanical and electrical limitations that would be introduced when combining electrical wires and optical fibers in a wireline cable.

Systems and methods for a treatment of chemical sensors placed in a wellbore. A method may comprise providing a chemical sensor disposed in a sensing chamber, wherein the chemical sensor is on an optical fiber installed in a wellbore; optically interrogating the chemical sensor with the optical fiber; and pumping a treatment fluid through a fluid supply line and into the sensing chamber.

In situ treatment of chemical sensors

Growing community of inventors

Houston, TX, United States of America

John Laureto Maida, Jr