METHOD AND SYSTEM FOR MONITORING FLUID FLUX IN A WELL

Abstract

Fluid flux in a fluid injection and/or hydrocarbon fluid production well is monitored in a cost efficient and accurate manner by inducing the fluid flux to move an acoustic emission device in a longitudinal direction through the well, measuring a longitudinal velocity (v) of the acoustic emission device at various longitudinally spaced locations in the well using a fiber optical Distributed Acoustic Sensing (DAS) assembly which monitors the longitudinal position of the acoustic emission device against time along at least part of the length of the well, and monitoring the fluid flux at various locations along the length of the well on the basis on the measured velocity (v) of the acoustic emission device.

Description

BACKGROUND OF THE INVENTION

[0001] The invention relates to a method and system for monitoring fluid flux in a fluid production and/or injection well.

[0002] Installation of flowmeters in wells is expensive and monitoring of influx of a multiphase well effluent mixture may require installation of a series of multiphase flowmeters throughout the length of an inflow region of the well.

[0003] It is known from U.S. Pat. No. 6,241,028 to intermittently measure the fluid flux and other data in a well tubular using a sensing device that is dragged by the fluid flux from an upstream end to a downstream end of the well tubular.

[0004] The known downhole sensing device comprises an accelerometer, a Micro Electro Mechanical System (MEMS) and a memory to monitor the position and velocity of the sensing device as it travels through the well tubular.

[0005] Disadvantages of the known downhole flow sensing device are that it is expensive to manufacture, deploy and read out and that it is vulnerable to damage and malfunctioning. Furthermore it is impractical to deploy the known downhole sensing device in a fluid injection well since the device can only be recovered if fluid injection is interrupted.

[0006] International patent application WO 2010/088681 discloses a system for monitoring flow in a wellbore, wherein a RFID or other marker is released in a flux of circulating drilling fluid and the motion of the marker through the wellbore is monitored by a range of RFID or other detectors that are distributed along the length of a drill or other tubing string within the wellbore. A disadvantage of this known system is that the range of RFID or other detectors only detect the motion of the marker at the point where the RFID or other detector is located and that no continuous motion detection of the marker along the length of the well is provided. Furthermore an increase of the amount of RFID or other detectors along the length of the wellbore will make the known system more expensive, complex and vulnerable to damage or malfunction.

[0007] US patent application US2012/0013893 discloses a wellbore communication system, wherein the movement of a transmitter through a wellbore is detected by a sensing device, which may include an optical waveguide arranged along the length of the wellbore. The transmitter may transmit acoustic and or other signals to the sensing device that allow determination of the position and/or the presence of the transmitter and the transmitter may comprise a sensor that measures physical parameters, such as pressure, temperature and/or pH.

[0008] This known wellbore communication system is not configured to monitor a velocity of the transmitter through the wellbore in order to determine a velocity of the produced well effluents since the optical waveguide is not part of a Distributed Acoustic Sensing (DAS) assembly, but generally detects Brillouin and/or Rayleigh backscattering resulting from light transmitted through the optical waveguide to determine the position and/or the presence of the transmitter and to convey the physical parameters, such as pressure, temperature and/or pH detected by the associated sensor.

[0009] There is a need for and improved downhole flow sensing device which can be manufactured and deployed in a cost effective manner, which is more robust and less vulnerable to damage and malfunctioning than the known device and which can be easily deployed to monitor fluid flux in a fluid injection well.

SUMMARY OF THE INVENTION

[0010] In accordance with the invention there is provided a method for monitoring fluid flux in a fluid production and/or injection well, the method comprising:

[0011] inducing the fluid flux to move an acoustic emission device in a longitudinal direction through the well;

[0012] measuring at various longitudinally spaced locations a longitudinal position of the acoustic emission device against time using a fiber optical Distributed Acoustic Sensing (DAS) assembly which is arranged along at least part of the length of the well;

[0013] calculating a longitudinal velocity of the acoustic emission device at the longitudinally spaced locations on the basis of the measured longitudinally spaced locations against time; and

[0014] monitoring the fluid flux at various locations along the length of the well on the basis of the measured velocities of the acoustic emission device at the longitudinally spaced locations.

[0015] In accordance with the invention there is furthermore provided a method of producing hydrocarbon fluid, such as crude oil and/or natural gas, from a hydrocarbon fluid containing formation, wherein the fluid injection and production rates in fluid injection and hydrocarbon fluid production wells traversing the formation are monitored by the method according to the invention.

[0016] In accordance with the invention there is furthermore provided a system for monitoring fluid flux in a fluid production and/or injection well. The system comprises:

[0017] an acoustic emission device which is configured to be moved by the fluid flux in a longitudinal direction through the well;

[0018] a fiber optical Distributed Acoustic Sensing (DAS) assembly which is arranged along at least part of the length of the well and configured to measure a longitudinal position of the acoustic emission device against time;

[0019] means for calculating a longitudinal velocity of the acoustic emission device at the longitudinally spaced locations on the basis of the measured longitudinally spaced locations against time; and

[0020] a display for monitoring the fluid flux at various locations along the length of the well on the basis of the measured velocities of the acoustic emission device at the longitudinally spaced locations.

[0021] The well may have a permeable fluid inflow and/or injection region and the display may be configured to monitor fluid influx and/or injection rates at various longitudinally spaced locations along the length of this region, on the basis of changes of the velocity of the acoustic emission device along the length of this region.

[0022] The well may be a fluid injection well through which fluid is injected through perforations in a perforated downhole section of the well into an underground oil and/or gas containing formation and the acoustic emission device may have a substantially spherical outer circumference with a larger width than the widths of the perforations. In such case a plurality of acoustic emission devices may be stored in a container which is configured to be stored near a wellhead of the injection well and which has a release mechanism that is configured to release from time to time one of the stored acoustic emission devices into the injection well.

[0023] Alternatively the well may be a hydrocarbon fluid production well through which hydrocarbon fluid is produced from an underground hydrocarbon fluid containing formation that is traversed by a permeable inflow section of the well and the DAS assembly may span at least a substantial part of the permeable inflow section and the acoustic emission device may be launched near an upstream end of the permeable inflow region to monitor the influx of hydrocarbon fluid at various longitudinally spaced locations along the length of the inflow region.

[0024] In such case a plurality of acoustic emission devices may be stored in a container which is configured to be installed at or near a bottom of the production well and which has a release mechanism that is configured to release from time to time one of the stored acoustic emission devices into the production tubing.

[0025] Optionally, the acoustic emission device has a density which is substantially similar to the density of the fluid in a lower part of the well so that the acoustic device is substantially neutrally buoyant in, and travels with substantially the same longitudinal velocity v as, the injected or produced fluid in the permeable lower part of the well.

[0026] These and other features, embodiments and advantages of the method and system according to the invention are described in the accompanying claims, abstract and the following detailed description of non-limiting embodiments depicted in the accompanying drawings, in which detailed description reference numerals are used which refer to corresponding reference numerals that are depicted in the drawings.

[0027] Similar reference numerals in different figures denote the same or similar objects.

BRIEF DESCRIPTION OF THE DRAWINGS

[0028] FIG. 1 is a schematic longitudinal sectional view of a fluid injection well in which fluid flux is measured using the method and system according to the invention; and

[0029] FIG. 2 is a schematic longitudinal sectional view of a hydrocarbon fluid production well in which fluid flux is measured using the method and system according to the invention.

DETAILED DESCRIPTION OF THE DEPICTED EMBODIMENTS

[0030] FIG. 1 depicts a fluid injection well 1 that has a permeable fluid injection section 1A that traverses an underground hydrocarbon fluid containing formation 2.

[0031] The well 1 comprises a wellhead 3 at the earth surface 4 from which a fluid injection tubing 5 is suspended in the well 1. The well 1 further comprises a well casing 6 that is secured to the surrounding hydrocarbon fluid containing formation 2 and overburden 8 by a cement sheath 7 and a packer 9 that provides a seal between an upper section 10 of annular space between the well casing 6 and injection tubing 5 from a lower section 11 of said space, which lower section is filled with a permeable gravel pack that surrounds a perforated lower section 5A of the injection tubing 5. Perforations 12 have been shot through the wall of the casing 6 and surrounding cement sheath 7 into the surrounding hydrocarbon fluid containing formation 2 to allow fluid to be injected from the interior of the injection tubing 5 into the surrounding hydrocarbon fluid containing formation 2 as illustrated by arrows 13. It will be understood that the well may have another completion type, such as an open hole completion with an uncased lower section.

[0032] A fiber optical Distributed Acoustic Sensing (DAS) cable 14 is bonded to the outer surface of the injection tubing 5 along at least a substantial part of the length of the tubing 5 and is connected to a DAS interrogation box 15, which transmits light pulses 1 through the fiber optical DAS cable and monitors time of flight, frequency and wavelength of backscattered light pulses b. The DAS interrogation box 15 is furthermore configured to monitor acoustic activity at various locations along the length of the fiber optical DAS cable on the basis of variations of the frequency and wavelength of the backscattered light pulses b at these locations resulting from strain variations in the fiber optical DAS cable 14 generated by the acoustic noise.

[0033] A container 16 containing a plurality of acoustic emission devices 17 is connected to the injection tubing 5 near the wellhead 3 is provided with a release mechanism 18 that is configured to release from time to time one of the acoustic emission devices 17 into the interior of the injection tubing 5. The release mechanism 18 also activates the released acoustic emission device 17 to transmit an acoustic noise n that can be detected by the fiber optical DAS cable 14.

[0034] The acoustic emission device 17 has a density which is substantially similar to the density of the injected fluid in the lower part of the injection tubing 5 so that the acoustic emission device is substantially neutrally buoyant in the injected fluid and moves with a substantially similar longitudinal velocity through the injection tubing 5 as the injected fluid 19.

[0035] Due to the discharge of fluid through the perforations 12 as illustrated by arrows 13 the longitudinal velocity of the fluid remaining in the injection tubing 5 and the longitudinal velocity v of the released acoustic emission device 17 will gradually decrease in downstream direction of the permeable fluid injection section 1A of the well 1 and the fluid discharge rates 13 passing through the various perforation 12 can be estimated on the basis of the decrease of longitudinal velocity v of the acoustic emission device 17 as it travels in a longitudinal direction along the length of the permeable fluid injection section 1A.

[0036] The changes of the longitudinal position against time and the decrease of longitudinal velocity v of the acoustic emission device 17 is monitored on the basis of time of flight of backscattered light pulses b, modified by the acoustic noise n, in the fiber optical DAS cable 14.

[0037] It will be understood that the fiber optical DAS cable 14 and DAS interrogation box 14 and the acoustic emission devices 17 can be manufactured and deployed in a cost effective manner, thereby providing a cost effective system and method for monitoring fluid flux 19 in the well 1 in an accurate manner at intermitted intervals during a prolonged period of time.

[0038] FIG. 2 depicts a hydrocarbon fluid production well 21 that has a permeable fluid inflow section 21A that traverses an underground hydrocarbon fluid, such as crude oil and/or natural gas, containing formation 22.

[0039] The well 21 comprises a wellhead 23 at the earth surface 24 from which a production tubing 25 is suspended into the well 21. The well 21 further comprises a well casing 26 that is secured to the surrounding hydrocarbon fluid containing formation 22 and overburden 28 by a cement sheath 27 and a packer 29 that provides a seal between an upper section 30 of annular space between the well casing 26 and production tubing 5 from a lower section 31 of said space, which lower section 31 is filled with a permeable gravel pack that surrounds a perforated lower section 25A of the production tubing 25.

[0040] Perforations 32 have been shot through the wall of the casing 26 and surrounding cement sheath 27 into the surrounding hydrocarbon fluid containing formation 22 to allow hydrocarbon fluid to flow from the formation 22 into the interior of the production tubing 25 as illustrated by arrows 33.

[0041] A fiber optical Distributed Acoustic Sensing (DAS) cable 34 is bonded to the outer surface of the production tubing 35 along at least a substantial part of the length of the tubing 35 and is connected to a DAS interrogation box 35, which transmits light pulses 1 through the fiber optical DAS cable 34 and monitors time of flight, frequency and wavelength of backscattered light pulses b. The DAS interrogation box 35 is furthermore configured to monitor acoustic activity at various locations along the length of the fiber optical DAS cable on the basis of variations of the frequency and wavelength of the backscattered light pulses b at these locations resulting from strain variations in the fiber optical DAS cable 34 generated by the acoustic noise.

[0042] A container 36 containing a plurality of acoustic emission devices 37 is arranged at the bottom of the production tubing 35 and is provided with a release mechanism 38 that is configured to release from time to time one of the acoustic emission devices 37 into the interior of the production tubing 25. The release mechanism 38 also activates the released acoustic emission device 37 to transmit an acoustic noise n that can be detected by the fiber optical DAS cable 34.

[0043] The acoustic emission device 37 has a density which is substantially similar to the density of the produced hydrocarbon fluid in the lower part of the production tubing 25 so that the acoustic emission device is substantially neutrally buoyant in the produced fluid and moves with a substantially similar longitudinal velocity v as the produced fluid 39 through the lower part of the production tubing 25.

[0044] Due to the influx of fluid through the perforations 32 as illustrated by arrows 33 the longitudinal velocity of the fluid flowing through the production tubing 25 and the longitudinal velocity v of the released acoustic emission device 37 will gradually increase in downstream direction of the permeable fluid injection section 21A of the well 21 and the fluid influx rates 33 passing through the various perforation 32 can be estimated on the basis of the increase of longitudinal velocity v of the acoustic emission device 37 as it travels upwards along the length of the permeable fluid inflow section 21A of the well 21.

[0045] The increase of longitudinal velocity v of the acoustic emission device 37 is monitored on the basis of time of flight of backscattered light pulses b, modified by the acoustic noise 38, in the fiber optical DAS cable 34.

[0046] It will be understood that the container 36 with a fresh set of acoustic emission devices 37 may be lowered into the well 21 during interruption of hydrocarbon fluid production or during workover and/or well maintenance and inspection operations.

[0047] It will furthermore be understood that the fiber optical DAS cable 34 and DAS interrogation box 34 and the acoustic emission devices 37 can be manufactured and deployed in a cost effective manner, thereby providing a cost effective system and method for monitoring hydrocarbon inflow rates 33 and fluid flux 39 in the well 21 in an accurate manner at intermitted intervals during a prolonged period of time.

Claims

1. A method for monitoring fluid flux in a fluid production and/or injection well comprises: inducing the fluid flux to move an acoustic emission device in a longitudinal direction through the well; measuring at various longitudinally spaced locations a longitudinal position of the acoustic emission device against time using a fiber optical Distributed Acoustic Sensing (DAS) assembly which is arranged along at least part of the length of the well; calculating a longitudinal velocity of the acoustic emission device at the longitudinally spaced locations on the basis of the measured longitudinally spaced locations against time; and monitoring the fluid flux at various locations along the length of the well on the basis of the measured longitudinal velocities of the acoustic emission device at the longitudinally spaced locations.

2. The method of claim 1, wherein the well has a permeable fluid inflow and/or injection region and the fluid inflow and/or injection rates at various locations along the length of this region are derived from changes of the longitudinal velocity of the acoustic emission device at various longitudinally spaced locations along the length of this region.

3. The method of claim 2, wherein the well is a fluid injection well through which fluid is injected through perforations in a permeable downhole section of the well into an underground oil and/or gas containing formation and the acoustic emission device has a substantially spherical outer circumference with a larger width than the widths of the perforations.

4. The method of claim 3, wherein a plurality of acoustic emission devices are stored in a container near a wellhead of the injection well from which one of the stored acoustic emission devices is released from time to time into the injection well.

5. The method of claim 2, wherein the well is a hydrocarbon fluid production well and the DAS assembly spans at least a substantial part of the length of an permeable inflow section of the well that traverses a hydrocarbon fluid containing formation and the acoustic emission device is launched near an upstream end of the permeable inflow section to monitor the influx of hydrocarbon fluid at various longitudinally spaced locations along the length of the permeable inflow section.

6. The method of claim 5, wherein a plurality of acoustic emission devices are stored in a container near a bottom of the production well from which from time to time one of the stored acoustic emission devices is released into the well.

7. The method of claim 1, wherein the density of the acoustic emission device is substantially similar to the density of the fluid in a lower part of the well.

8. A method of producing hydrocarbon fluid from a hydrocarbon fluid containing formation, wherein the fluid injection and production rates in fluid injection and hydrocarbon fluid production wells traversing the formation are monitored in accordance with the method according to claim 1.

9. A system for monitoring fluid flux in a fluid production and/or injection well, the system comprising: an acoustic emission device which is configured to be moved by the fluid flux in a longitudinal direction through the well; a fiber optical Distributed Acoustic Sensing (DAS) assembly which is arranged along at least part of the length of the well and configured to measure at various longitudinally spaced locations a longitudinal position of the acoustic emission device against time; means for calculating a longitudinal velocity of the device at the longitudinally spaced positions on the basis of changes of the measured longitudinal positions against time; and a display for monitoring the fluid flux at various locations along the length of the well on the basis of the calculated velocities of the acoustic emission device at the longitudinally spaced locations.

10. The system of claim 9, wherein the well has a permeable fluid inflow and/or injection region and the display is furthermore configured to monitor fluid influx and/or injection rates at various locations along the length of this region, on the basis of changes of the longitudinal velocity of the acoustic emission device along the length of this region.

11. The system of claim 10, wherein the well is a fluid injection well through which fluid is injected through perforations in a perforated downhole section of the well into an underground oil and/or gas containing formation and the acoustic emission device has a substantially spherical outer circumference with a larger width than the widths of the perforations.

12. The system of claim 11, wherein a plurality of acoustic emission devices are stored in a container which is configured to be stored near a wellhead of the injection well and which has a release mechanism that is configured to release from time to time one of the stored acoustic emission devices into the injection well.

13. The system of claim 9, wherein the well is a hydrocarbon fluid production well through which hydrocarbon fluid is produced from an underground hydrocarbon fluid containing formation that is traversed by a permeable inflow section of the well and the DAS assembly spans at least a substantial part of the permeable inflow section and the acoustic emission device is launched near an upstream end of the permeable inflow region to monitor the influx of hydrocarbon fluid at various longitudinally spaced locations along the length of the inflow region.

14. The system of claim 13, wherein a plurality of acoustic emission devices are stored in a container which is configured to be installed at or near a bottom of the production well and which has a release mechanism that is configured to release from time to time one of the stored acoustic emission devices into the production tubing.

15. The system of claim 9, wherein the acoustic emission device has a density which is substantially similar to the density of the fluid in a lower part of the well.

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