Data transmission across downhole connections

• US 10,253,622 B2
• Filed: 12/16/2015
• Issued: 04/09/2019
• Est. Priority Date: 12/16/2015
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Jaaskelainen, Mikko, Park, Brian Vandellyn
• Primary Examiner(s): Bousono, Orlando
• Application Number:
  US15/775,715
• Publication Number:
  US 20180347348A1
• Time in Patent Office: 1,210 Days
• CPC Class Codes: E21B 41/0085 Adaptations of electric power generating means for use in boreholes
• CPC Class Codes: E21B 47/06 Measuring temperature or pressure
• CPC Class Codes: E21B 47/135 using light waves, e.g. infrared or ultraviolet waves
• CPC Class Codes: E21B 47/14 using acoustic waves
• CPC Class Codes: E21B 47/16 through the drill string or casing , e.g. by torsional acoustic waves
• CPC Class Codes: E21B 47/18 through the well fluid , e.g. mud pressure pulse telemetry
• CPC Class Codes: G01S 15/8965 using acousto-optical or acousto-electronic conversion techniques

Abstract

Various embodiments include methods and systems structured to transmit data from downhole sensors to the surface at a well site. The transmission can be implemented to overcome downhole connections that can act as obstructions to direct electrical and optical communication in a wellbore. Electrical signals from one or more sensors in a sensor unit, located on a side of a downhole connection in a wellbore opposite the surface of the wellbore, can be used to drive an acoustic transmitter to transmit an acoustic signal via a production string or casing or fluid in the production string or casing across the downhole connection, where the acoustic signal is received on the surface side of the downhole connection. Data correlated to the received acoustic signal can be provided to a surface location of the wellbore. Additional apparatus, systems, and methods can be implemented in a variety of applications.

Claims

1. A method comprising:

generating an electrical signal from a sensor unit coupled to a production string or casing in a wellbore, the sensor unit having one or more sensors, the electrical signal indicative of a parameter measured by the one or more sensors;

transmitting an acoustic signal by an electroacoustic transmitter coupled to the production string or casing, the acoustic signal correlated to the electrical signal, the acoustic signal transmitted via the production string or casing or fluid in the production string or casing;

receiving the acoustic signal in an acoustic receiver coupled to the production string or casing above the electroacoustic transmitter with respect to fluid flow to a surface location, the acoustic receiver separated from the electroacoustic transmitter by a downhole connection that obstructs direct electrical transmission and optical transmission between the electroacoustic transmitter and the acoustic receiver; and

providing data correlated to the received acoustic signal to the surface location of the wellbore.

2. The method of claim 1, wherein providing data correlated to the received acoustic signal to the surface location of the wellbore includes using an optical fiber system to transmit the data to the surface location.

3. The method of claim 2, wherein providing data correlated to the received acoustic signal to the surface location includes using a distributed acoustic sensing system that receives the data in acoustic form.

4. The method of claim 3, wherein using the distributed acoustic sensing system includes applying an interferometric technique.

5. The method of claim 4, wherein applying an interferometric technique includes using coherent Rayleigh scattering.

6. The method of claim 3, wherein receiving the acoustic signal in the acoustic receiver includes receiving the acoustic signal in an acoustic receiver coupled to the distributed acoustic sensing system.

7. The method of claim 1, wherein generating the electrical signal from a sensor unit and transmitting the acoustic signal includes transmitting the acoustic signal from the electroacoustic transmitter integrated in the sensor unit;

and receiving the acoustic signal includes receiving the acoustic signal in an distributed acoustic sensing system separated from the sensor unit by the downhole connection in the production string or casing.

8. The method of claim 7, wherein the method includes converting an electrical signal, from a second sensor unit coupled to the sensor unit by electrical wiring, to an acoustic signal containing data from one or more sensors of the second sensor unit, and transmitting an acoustic signal containing the data from the one or more sensors of the second sensor unit across the downhole connection.

9. The method of claim 1, wherein the method includes powering the sensor unit by a vortex harvester that provides energy to the sensor unit from flow of fluid in the production string or casing.

10. The method of claim 1, wherein the method includes generating a plurality of acoustic signals from conversion of electrical signals by one or more additional sensor units coupled to the production string or casing, each additional sensor unit having one or more sensors, the electrical signals being generated at a frequency different from that of the other sensor units or the electrical signals being time multiplexed with a unique identifier for each electrical signal.

11. The method of claim 1, wherein the method includes receiving commands in the sensor unit to control the one or more sensors.

12. A system comprising:

a sensor unit coupled to a production string or casing in a wellbore, the sensor unit having one or more sensors, the sensor unit operable to output an electrical signal indicative of a parameter measured by the one or more sensors;

an electroacoustic transmitter coupled to the production string or casing in the wellbore and structured to transmit an acoustic signal via the production string or casing or fluid in the production string or casing, the acoustic signal correlated to the electrical signal; and

an acoustic receiver coupled to the production string or casing above the electroacoustic transmitter with respect to fluid flow to a surface location, the acoustic receiver separated from the electroacoustic transmitter by a downhole connection that obstructs direct electrical transmission and optical transmission between the electroacoustic transmitter and the acoustic receiver, the acoustic receiver device operable to receive the acoustic signal.

13. The system of claim 12, wherein the acoustic receiver includes an acoustic receiver arranged to amplify data in the acoustic signal and transmit the amplified data to an optical fiber system or a fiber optic sensor coupled to the optical fiber system.

14. The system of claim 13, wherein the optical fiber system includes a distributed acoustic sensing system.

15. The system of claim 14, wherein the sensor unit includes a vortex harvester to provide energy to the sensor unit from flow of fluid in the production string or casing.

16. The system of claim 15, wherein the vortex harvester is operable to detect fluid velocity.

17. The system of claim 12, wherein the one or more sensors include temperature and pressure sensors.

18. The system of claim 12, wherein the system includes one or more additional sensor units, each additional sensor unit having one or more sensors, the one or more additional sensor units coupled to the production string or casing and arranged to provide electrical signals, having sensor data, to the electroacoustic transmitter for acoustic transmission of the sensor data across the downhole connection, the electrical signals being generated at a frequency different from that of the other sensor units or the electrical signals being time multiplexed with a unique identifier for each electrical signal.

19. The system of claim 12, wherein the acoustic receiver includes a distributed acoustic sensing system to receive the acoustic signal directly from the production string or casing or the fluid in the production string or casing.

20. The system of claim 12, wherein the electroacoustic transmitter is electrically connected to the sensor unit to share an operating power source or the electroacoustic transmitter includes a vortex harvester to provide energy to the electroacoustic transmitter from flow of fluid in the production string or casing.

21. The system of claim 12, wherein the acoustic receiver includes a piezoelectric receiver to receive the acoustic signal and a piezoelectric transmitter to transmit a representation of the acoustic signal to a distributed acoustic sensing system.