AU2014315152A1 - Method and system for monitoring fluid flux in a well - Google Patents
Method and system for monitoring fluid flux in a well Download PDFInfo
- Publication number
- AU2014315152A1 AU2014315152A1 AU2014315152A AU2014315152A AU2014315152A1 AU 2014315152 A1 AU2014315152 A1 AU 2014315152A1 AU 2014315152 A AU2014315152 A AU 2014315152A AU 2014315152 A AU2014315152 A AU 2014315152A AU 2014315152 A1 AU2014315152 A1 AU 2014315152A1
- Authority
- AU
- Australia
- Prior art keywords
- well
- fluid
- acoustic emission
- emission device
- injection
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Granted
Links
- 239000012530 fluid Substances 0.000 title claims abstract description 106
- 230000004907 flux Effects 0.000 title claims abstract description 26
- 238000012544 monitoring process Methods 0.000 title claims abstract description 16
- 238000000034 method Methods 0.000 title claims description 21
- 238000002347 injection Methods 0.000 claims abstract description 44
- 239000007924 injection Substances 0.000 claims abstract description 44
- 238000004519 manufacturing process Methods 0.000 claims abstract description 32
- 239000004215 Carbon black (E152) Substances 0.000 claims abstract description 31
- 229930195733 hydrocarbon Natural products 0.000 claims abstract description 31
- 150000002430 hydrocarbons Chemical class 0.000 claims abstract description 31
- 230000003287 optical effect Effects 0.000 claims abstract description 22
- 239000000835 fiber Substances 0.000 claims abstract description 19
- 230000001939 inductive effect Effects 0.000 claims abstract description 3
- 230000015572 biosynthetic process Effects 0.000 claims description 18
- 230000004941 influx Effects 0.000 claims description 8
- 238000011144 upstream manufacturing Methods 0.000 claims description 4
- 230000005534 acoustic noise Effects 0.000 description 6
- 239000004568 cement Substances 0.000 description 4
- 239000003550 marker Substances 0.000 description 4
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 4
- 238000004891 communication Methods 0.000 description 2
- 239000010779 crude oil Substances 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 238000009434 installation Methods 0.000 description 2
- 239000003345 natural gas Substances 0.000 description 2
- 230000002035 prolonged effect Effects 0.000 description 2
- 238000001514 detection method Methods 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 239000007789 gas Substances 0.000 description 1
- 238000007689 inspection Methods 0.000 description 1
- 238000012423 maintenance Methods 0.000 description 1
- 230000007257 malfunction Effects 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 239000003921 oil Substances 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/10—Locating fluid leaks, intrusions or movements
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/10—Locating fluid leaks, intrusions or movements
- E21B47/107—Locating fluid leaks, intrusions or movements using acoustic means
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
- E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency
- E21B47/135—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency using light waves, e.g. infrared or ultraviolet waves
Landscapes
- Engineering & Computer Science (AREA)
- Physics & Mathematics (AREA)
- Life Sciences & Earth Sciences (AREA)
- Mining & Mineral Resources (AREA)
- Geology (AREA)
- Geophysics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Remote Sensing (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Electromagnetism (AREA)
- Acoustics & Sound (AREA)
- Geophysics And Detection Of Objects (AREA)
- Loading And Unloading Of Fuel Tanks Or Ships (AREA)
- Measurement Of Mechanical Vibrations Or Ultrasonic Waves (AREA)
Abstract
Fluid flux in a fluid injection and/or hydrocarbon fluid production well (1, 21) is monitored in a cost efficient and accurate manner by: - inducing the fluid flux to move an acoustic emission device (17, 37) in a longitudinal direction through the well (1, 21); - measuring a longitudinal velocity (v) of the acoustic emission device (17, 37) at various longitudinally spaced locations in the well (1, 21) using a fiber optical Distributed Acoustic Sensing (DAS) assembly (14, 15, 34, 35) which monitors the longitudinal position of the acoustic emission device against time along at least part of the length of the well (1, 21); and - monitoring the fluid flux (13, 19, 33, 39) at various locations along the length of the well (1, 21) on the basis on the measured velocity (v) of the acoustic emission device (17, 37).
Description
WO 2015/035060 PCT/US2014/054109 METHOD AND SYSTEM FOR MONITORING FLUID FLUX IN A WELL BACKGROUND OF THE INVENTION The invention relates to a method and system for monitoring fluid flux in a fluid 5 production and/or injection well. 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. It is known from US patent 6,241,028 to intermittently measure the fluid flux and 10 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. 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. 15 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. 20 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 25 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. 30 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 1 WO 2015/035060 PCT/US2014/054109 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. This known wellbore communication system is not configured to monitor a velocity 5 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 thephysical parameters, such as pressure, 10 temperature and/or pH detected by the associated sensor. 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. 15 SUMMARY OF THE INVENTION 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: 20 - 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; 25 - 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 velocities of the acoustic emission device at the longitudinally spaced 30 locations. 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 2 WO 2015/035060 PCT/US2014/054109 injection and hydrocarbon fluid production wells traversing the formation are monitored by the method according to the invention. 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: 5 - 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 a longitudinal position of the acoustic emission device against time; 10 - 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 - 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 15 spaced locations. 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. 20 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 25 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. Alternatively the well may be a hydrocarbon fluid production well through which hydrocarbon fluid is produced from an underground hydrocarbon fluid containing 30 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 3 WO 2015/035060 PCT/US2014/054109 region to monitor the influx of hydrocarbon fluid at various longitudinally spaced locations along the length of the inflow region. 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 5 has a release mechanism that is configured to release from time to time one of the stored acoustic emission devices into the production tubing. 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 10 velocity v as, the injected or produced fluid in the permeable lower part of the well. 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 15 corresponding reference numerals that are depicted in the drawings. Similar reference numerals in different figures denote the same or similar objects. BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is a schematic longitudinal sectional view of a fluid injection well in 20 which fluid flux is measured using the method and system according to the invention; and Figure 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. 25 DETAILED DESCRIPTION OF THE DEPICTED EMBODIMENTS Figure 1 depicts a fluid injection well 1 that has a permeable fluid injection section 1A that traverses an underground hydrocarbon fluid containing formation 2. 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 30 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 4 WO 2015/035060 PCT/US2014/054109 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 5 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. 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 10 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 15 generated by the acoustic noise. 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 20 acoustic emission device 17 to transmit an acoustic noise n that can be detected by the fiber optical DAS cable 14. 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 25 substantially similar longitudinal velocity through the injection tubing 5 as the injected fluid 19. 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 30 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 5 WO 2015/035060 PCT/US2014/054109 travels in a longitudinal direction along the length of the permeable fluid injection section 1A. 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 5 of flight of backscattered light pulses b, modified by the acoustic noise n, in the fiber optical DAS cable 14. 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 10 fluid flux 19 in the well 1 in an accurate manner at intermitted intervals during a prolonged period of time. Figure 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. 15 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 20 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. 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 25 as illustrated by arrows 33. 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 30 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 6 WO 2015/035060 PCT/US2014/054109 backscattered light pulses b at these locations resulting from strain variations in the fiber optical DAS cable 34 generated by the acoustic noise. 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 5 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. The acoustic emission device 37 has a density which is substantially similar to the 10 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. Due to the influx of fluid through the perforations 32 as illustrated by arrows 33 the 15 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 20 travels upwards along the length of the permeable fluid inflow section 21 A of the well 21. 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. It will be understood that the container 36 with a fresh set of acoustic emission 25 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. 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 30 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. 7
Claims (15)
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 5 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; 10 - 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 15 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 20 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 25 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 30 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 8 WO 2015/035060 PCT/US2014/054109 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 5 one of the stored acoustic emission devices is released into the well.
7. The method of any one of claims 1-6, 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 10 hydrocarbon fluid production wells traversing the formation are monitored in accordance with the method according to any one of claims 1-7.
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 15 a longitudinal direction through the well; - a fiber optical Distributed Acoustic Sensing (DAS) assembly which isarranged 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; 20 - 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 25 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 30 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 9 WO 2015/035060 PCT/US2014/054109 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 5 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 10 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 15 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 any one of claims 9-14, wherein the acoustic emission device has a 20 density which is substantially similar to the density of the fluid in a lower part of the well. 10
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| EP13183188.5 | 2013-09-05 | ||
| EP13183188 | 2013-09-05 | ||
| PCT/US2014/054109 WO2015035060A1 (en) | 2013-09-05 | 2014-09-04 | Method and system for monitoring fluid flux in a well |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| AU2014315152A1 true AU2014315152A1 (en) | 2016-04-07 |
| AU2014315152B2 AU2014315152B2 (en) | 2016-09-08 |
Family
ID=49118372
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| AU2014315152A Ceased AU2014315152B2 (en) | 2013-09-05 | 2014-09-04 | Method and system for monitoring fluid flux in a well |
Country Status (5)
| Country | Link |
|---|---|
| US (1) | US20160230541A1 (en) |
| AU (1) | AU2014315152B2 (en) |
| CA (1) | CA2922373A1 (en) |
| GB (1) | GB2535035B (en) |
| WO (1) | WO2015035060A1 (en) |
Families Citing this family (7)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10920581B2 (en) | 2016-06-30 | 2021-02-16 | Shell Oil Company | Flow velocity meter and method of measuring flow velocity of a fluid |
| EP3472429A4 (en) | 2016-09-26 | 2020-02-26 | Halliburton Energy Services, Inc. | Wellbore sand detection using passive acoustic array |
| GB2566910B (en) | 2016-10-13 | 2021-08-25 | Halliburton Energy Services Inc | Systems and methods to utilize a sensor to provide spatial resolution in downhole leak detection |
| WO2018217207A1 (en) | 2017-05-25 | 2018-11-29 | Halliburton Energy Services, Inc. | Systems and methods to use triangulation through one sensor beamforming in downhole leak detection |
| MX2020003353A (en) | 2017-12-29 | 2020-07-29 | Halliburton Energy Services Inc | Systems and methods to utilize sensors to provide spatial rosolution in downhole leak detection. |
| US10247838B1 (en) * | 2018-01-08 | 2019-04-02 | Saudi Arabian Oil Company | Directional sensitive fiber optic cable wellbore system |
| WO2019224567A1 (en) * | 2018-05-22 | 2019-11-28 | Total Sa | Apparatus for measuring fluid flow in a well, related installation and process |
Family Cites Families (6)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US5991602A (en) * | 1996-12-11 | 1999-11-23 | Labarge, Inc. | Method of and system for communication between points along a fluid flow |
| AR018460A1 (en) * | 1998-06-12 | 2001-11-14 | Shell Int Research | METHOD AND PROVISION FOR MEASURING DATA FROM A TRANSPORT OF FLUID AND SENSOR APPLIANCE USED IN SUCH DISPOSITION. |
| US6443228B1 (en) * | 1999-05-28 | 2002-09-03 | Baker Hughes Incorporated | Method of utilizing flowable devices in wellbores |
| US8584519B2 (en) * | 2010-07-19 | 2013-11-19 | Halliburton Energy Services, Inc. | Communication through an enclosure of a line |
| EP2656112A2 (en) * | 2010-12-21 | 2013-10-30 | Shell Internationale Research Maatschappij B.V. | Detecting the direction of acoustic signals with a fiber optical distributed acoustic sensing (das) assembly |
| US20140202240A1 (en) * | 2013-01-24 | 2014-07-24 | Halliburton Energy Services, Inc. | Flow velocity and acoustic velocity measurement with distributed acoustic sensing |
-
2014
- 2014-09-04 WO PCT/US2014/054109 patent/WO2015035060A1/en active Application Filing
- 2014-09-04 CA CA2922373A patent/CA2922373A1/en not_active Abandoned
- 2014-09-04 GB GB1603352.4A patent/GB2535035B/en not_active Expired - Fee Related
- 2014-09-04 AU AU2014315152A patent/AU2014315152B2/en not_active Ceased
- 2014-09-04 US US14/916,786 patent/US20160230541A1/en not_active Abandoned
Also Published As
| Publication number | Publication date |
|---|---|
| CA2922373A1 (en) | 2015-03-12 |
| GB201603352D0 (en) | 2016-04-13 |
| AU2014315152B2 (en) | 2016-09-08 |
| WO2015035060A1 (en) | 2015-03-12 |
| US20160230541A1 (en) | 2016-08-11 |
| GB2535035A (en) | 2016-08-10 |
| GB2535035B (en) | 2017-04-05 |
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|---|---|---|---|
| FGA | Letters patent sealed or granted (standard patent) | ||
| MK14 | Patent ceased section 143(a) (annual fees not paid) or expired |