The invention relates generally to systems and methods for transmitting power and data through a coiled tubing string.
Coiled tubing is commonly used as a running string for a wide variety of downhole tools. Telecoil® is sometimes used to transmit power and data through coiled tubing. Telecoil is coiled tubing which includes tubewire within coiled tubing. Tubewire is a tube that contains an insulated cable that is used to provide electrical power and/or data to a bottom hole assembly (BHA) or to transmit data from the BHA to the surface. Tube-wire is available commercially from manufacturers such as Canada Tech Corporation of Calgary, Canada.
The present invention relates to systems and methods for transmitting electrical power and/or signals as well as optical signals within coiled tubing and along a wellbore.
A coiled tubing system is described which includes a string of coiled tubing which defines a central flowbore along its length. An electrical wire conduit and an optic fiber are disposed within the flowbore. In certain embodiments, the electrical wire conduit and optic fiber are enclosed within an outer protective tube within the flowbore. In preferred embodiments, the electrical wire conduit and optic fiber are first enclosed within an outer tube to form a tube assembly. The tube assembly is then inserted into a string of coiled tubing.
A coiled tubing system constructed in accordance with the present invention allows for bottom hole assemblies to be deployed which incorporate one or more sensors, which can detect one or more first downhole operating parameters, including depth, pressure, temperature, gamma and the like. Electrical power is transferred along the electrical wire conduit to the one or more sensors. In addition, the coiled tubing system affords the advantage of being able to sense a second downhole operating parameter, such as temperature or acoustic information, along the length of the coiled tubing string during operation.
For a thorough understanding of the present invention, reference is made to the following detailed description of the preferred embodiments, taken in conjunction with the accompanying drawings, wherein like reference numerals designate like or similar elements throughout the several figures of the drawings and wherein:
A coiled tubing injector (not shown) of a type known in the art is located at surface 12 and is used to inject coiled tubing into the wellbore 10. A controller 16 is also located at surface 12. The controller 16 is preferably a programmable device, such as a computer, which is capable of receiving data in the form of electrical signals from a downhole sensor arrangement for display to a user and/or for storage. Additionally, an electrical power source 18 is located at surface 12 and may be in the form of a generator or battery. The electrical power source 18 should be suitable for transmitting power downhole to a sensor. Also located at surface 12 is an OTDR (optical time-domain reflectometer) 20.
A coiled tubing-based work string, generally indicated at 22, is shown being injected into the wellbore 10. The work string 22 includes a dual telemetric coiled tubing running string 24 which defines a central flowbore 26 along its length.
A bottom hole assembly 28 (BHA) is located at the distal end of the coiled tubing running string 24. The bottom hole assembly 28 may be a fishing BHA, an acidizing/fracturing BHA, or a cleanout BHA. Alternatively, the bottom hole assembly 28 could be any electrically powered tool, such as an electric submersible pump or a tool for opening and closing sliding sleeves.
The bottom hole assembly 28 includes one or more sensors 30 to detect at least one first operating parameter associated with the wellbore 10. Exemplary operating parameters include wellbore temperature and pressure as well as measurements relating to depth, gamma and the like. Sensor(s) 30 may be placed on the exterior surface of the bottom hole assembly 28, as illustrated in
With further reference to
The optic fiber 34 will typically include a transparent central core with outer cladding which has a lower index of refraction than that of the core. The optic fiber 34 will include a number of Bragg gratings 36 (
During operation of the work string 22, the optic fiber 34 provides optical telemetry to the OTDR 20 which is indicative of at least one second operating parameter within the wellbore 10. In certain embodiments, the optic fiber 34 and OTDR 20 are configured to perform distributed temperature sensing (DTS) or distributed acoustic sensing (DAS) and provide telemetry to the OTDR 20. The optic fiber 34 and OTDR 20 can provided information regarding sensed temperature or acoustics along the length of the optic fiber 34.
Preferably, either of both of the electrical wire conduit 32 and the optic fiber 34 are encased with a protective tube within the flowbore 26.
The electric wire conduit 32 is operably connected with the sensor(s) 30 downhole and with the controller 16 and electrical power source 18 at surface 12. Although depicted in the drawing as separate components, it should be understood that the controller 16 and power source 18 may be combined such that the controller 16 functions as a power source as well. In alternative embodiments, the power source 30 at surface may be supplemented by downhole batteries. The sensor(s) 30 provide sensed data to the controller 16 at surface 12.
In an exemplary operation, the coiled tubing running string 24/24′ allows for dual telemetry transmission to occur. First, information from the optic fiber 34 is provided to the OTDR 20 which is indicative of a first downhole operating parameter (i.e., temperature or acoustic) within the flowbore 26. Second, information from sensor(s) 30 is transmitted which is representative of at least one second downhole operating parameter in the vicinity of the bottom hole assembly 28. Having access to both data from the optic fiber 34 and the downhole sensor(s) 30 allows combination of DTS/DAS methods with Telecoil. For instance, DTS could be used for flow profiling along the entire length of the coiled tubing running string 24 or 24′, while the data from sensor(s) 30 could be used for accurate depth measurement or for DTS calibration. If the sensor(s) 30 include temperature sensor(s), these could be in direct contact with well fluids to measure well fluid temperature. Because the optic fiber 34 is located within the flowbore 26, it is not in direct contact with the well fluid that is located outside of the coiled tubing running string 24/24′. Thus, any temperature measurements provided by the optic fiber 34 are “static,” meaning that the coiled tubing running string needs to be stationary within the wellbore in order for temperature changes in the well fluid to be measured by the optic fiber 34. With data from both the optic fiber 34 and the sensor(s) 30, the work string 22 could be moved, and any temperature changes sensed by the optic fiber 34 would be qualitative, meaning that the optic fiber 34 could indicate the locations within the wellbore 10 where the well fluid temperature is changing, further indicating the locations of fluid flow.
Those of skill in the art will recognize that numerous modifications and changes may be made to the exemplary designs and embodiments described herein and that the invention is limited only by the claims that follow and any equivalents thereof.
Filing Document | Filing Date | Country | Kind |
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PCT/US2016/060998 | 11/8/2016 | WO | 00 |
Publishing Document | Publishing Date | Country | Kind |
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WO2018/088994 | 5/17/2018 | WO | A |
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Number | Date | Country | |
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20190257194 A1 | Aug 2019 | US |