EP2909440A1 - Flow velocity and acoustic velocity measurement with distributed acoustic sensing - Google Patents
Flow velocity and acoustic velocity measurement with distributed acoustic sensingInfo
- Publication number
- EP2909440A1 EP2909440A1 EP14743240.5A EP14743240A EP2909440A1 EP 2909440 A1 EP2909440 A1 EP 2909440A1 EP 14743240 A EP14743240 A EP 14743240A EP 2909440 A1 EP2909440 A1 EP 2909440A1
- Authority
- EP
- European Patent Office
- Prior art keywords
- acoustic
- velocity
- well
- pressure pulse
- optical waveguide
- 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
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
Definitions
- This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an example described below, more particularly provides for flow velocity and acoustic velocity measurement with distributed acoustic sensing.
- compositions and flow rates in wells may be used in production, injection, stimulation, conformance, or other types of well operations.
- FIG. 1 is a representative partially cross-sectional view of a well system and associated method which can embody principles of this disclosure.
- FIG. 2 is a representative plot of pressure pulse location versus time.
- FIG. 3 is a representative plot of pressure pulse velocity versus time.
- FIG. 4 is a representative plot of acoustic pulse location versus time.
- FIG. 1 Representatively illustrated in FIG. 1 is a well flow velocity measurement system 10 and associated method which can embody principles of this disclosure.
- system 10 and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this
- This disclosure provides unique techniques for
- the wellbore 12 is generally vertical and is lined with casing 14 and cement 16. However, in other examples, the wellbore 12 may be generally
- a pressure pulse 18 is transmitted through the wellbore 12.
- the pressure pulse 18 may be transmitted from the earth's surface, or from another location in the well.
- a pressure pulse generator 30 may be used to produce positive and/or negative pressure pulses, which propagate through the fluids in the wellbore 12.
- Pressure pulses can be positive where a compressed air or nitrogen gun is used to dump a pre-charged volume of gas into the wellbore 12.
- pressurized well fluids may be dumped into an evacuated chamber to generate a negative pressure pulse.
- flow exiting a well may be modulated by a choke or valve at the surface to generate either positive or negative pulses, or both.
- HalSonics (TM) system marketed by HalSonics (TM)
- a pressure pulse can also be generated by striking a structure in the well, such as a tubular string, the casing 14, etc. When the structure is impacted, a pressure wave develops in contents of the structure and propagates away from a location of the impact.
- a mechanism could, for example, deliver a hammer impact driven by differential pressure, an electromagnetic solenoid, or other mechanical actuator .
- the pressure pulses 18 could be generated by detonating a series of explosive or other exothermic devices in the well. Thus, the scope of this disclosure is not limited to any particular manner of generating the pressure pulses 18.
- the pressure pulses 18 it is not necessary for the pressure pulses 18 to be generated at or near the earth's surface. In some examples, the pressure pulses 18 could be generated at or near a bottom of the wellbore 12, at some location between the surface and the bottom of the wellbore, etc. If the pressure pulses 18 are generated at a location between the surface and the bottom of the wellbore 12, then the pulses can travel in opposite directions via the wellbore from the location where they were generated.
- the pressure pulses 18 are detected by means of a sensor located in the well.
- the sensor comprises an optical waveguide 22 (such as, an optical fiber or ribbon), which may be part of a cable including one or more optical waveguides, electrical conductors, hydraulic conduits, etc.
- the sensor is preferably part of a
- DAS distributed acoustic sensing
- DAS distributed acoustic sensing
- the distributed along the optical waveguide 22 can be measured by detecting coherent Rayleigh backscattering in the
- the DAS system 20 of FIG. 1 comprises surface optics, electronics and software, commonly known to those skilled in the art as an interrogator 24, and the optical waveguide 22.
- the optical waveguide 22 may be installed in the wellbore 12, inside or outside of the casing 14 or other tubulars, optionally in the cement 16 surrounding the casing, etc.
- the interrogator 24 launches light into the optical waveguide 22 (e.g., from an infrared laser or other light source 26).
- a detector 28 detects the light returned via the same optical waveguide 22.
- the DAS system 20 uses
- backscattered light e.g., coherent Rayleigh backscattering
- an array of weak fiber Bragg gratings or other artificially introduced reflectors can be used with the optical waveguide 38 to detect acoustic signals along the waveguide.
- the interrogator 24 and/or the pressure pulse generator 30 may be controlled via a control system 32, for example, including at least a processor 34 and memory 36.
- Signal processing is used to segregate the waveguide 22 into an array of individual "microphones" or acoustic sensors, typically corresponding to 1-10 meter segments of the waveguide .
- the waveguide 22 may be housed in a metal tubing or control line and positioned in the wellbore 12. In some examples, the waveguide 22 may be in cement surrounding the casing 14, in a wall of the casing or other tubular,
- the pressure pulse 18 is reflected back through the wellbore 12, and the reflected pressure pulse 38 is also detected by the DAS system 20.
- the DAS system 20 detects the propagation of the pressure pulse 18 and the reflected pressure pulse 38 as they displace through the wellbore 12.
- the pressure pulse 18 may be reflected off of a bottom of the well, off of a plug or other obstruction in the wellbore 12, or at a fluid/air or fluid/metal interface at or near the surface.
- other changes in acoustic impedance can cause the pressure pulse 18 to be reflected.
- Such changes in acoustic impedance can include changes in acoustic velocity due to changes in fluid composition in the wellbore 12, changes in casing 14 diameter, etc.
- the scope of this disclosure is not limited to any particular manner of producing the reflected pressure pulse 38.
- flow velocity, V f and acoustic velocity, V a of fluid compositions in the wellbore 12 can be readily determined. If flow velocity is known, a volumetric flow rate can be readily calculated by multiplying the flow velocity by flow area.
- the acoustic velocity V a in a fluid composition depends on the fluids in the composition and a compliance of a pipe or conduit containing the fluid composition. If one knows the acoustic velocity of the fluid composition, the fluids in the composition (for example, an oil/water ratio) can be readily estimated.
- FIG. 1 example two sets of perforations 42a, b are depicted in the casing 14, so that respective fluid compositions 40a, b are produced into the wellbore 12. Below the bottom perforations 42a, no flow enters the well.
- the pressure pulse 18 is generated at the surface, which causes an acoustic wave or signal to travel from the surface through the wellbore 12 with velocity V 0 (in this case, opposing the direction of flow of the fluids 40a, b) .
- V 0 in this case, opposing the direction of flow of the fluids 40a, b
- V w velocity of the fluids 40a, b
- the reflected pulse 38 may return to the surface and be reflected again through the wellbore 12.
- the optical waveguide 22 installed in the well and connected to the DAS interrogator 24, it is possible to observe the propagation of the pulses 18, 38, and it may be possible to observe multiple round trips of a pressure pulse.
- Reflections will occur whenever there is a change in acoustic impedance. For fluids in pipe, such changes occur, for example, when an end of the pipe is blocked by a plug, when the inner diameter of the pipe changes, or if the pipe terminates inside another pipe with a larger diameter, etc. Amplitudes and signs of reflected pulses are readily
- the pressure pulse or acoustic wave propagates in either direction, it decreases in amplitude due to losses, and spreads out due to dispersion.
- the wave may be detected moving back and forth through the wellbore 12 for an extended period of time, it is advantageous to measure the velocity of wave propagation early on while the wave amplitude is relatively high and its pulse width is
- reflections 38 can be readily determined using the DAS interrogator 24, for example, by dividing displacement of the signals by elapsed time. Using this information, with the system 10 configured as depicted in FIG. 1, an acoustic velocity in the commingled fluids 40a, b can be determined, as well as a velocity of the commingled fluids through the wellbore 12.
- V 0 V a - V f (2)
- V w the velocity of a signal traveling with the flow of fluid (in the FIG. 1 example, the reflected signal 38)
- V 0 is the velocity of a signal traveling opposite the flow of fluid (in the FIG. 1 example, the generated signal 18)
- V a is the acoustic velocity in the commingled fluids 40a, b
- V f is the velocity of the fluids through the wellbore 12.
- V a (V w + V 0 )/2 (3) and, thus, the acoustic velocity V a is simply the average of the velocities of the generated signal 36a and the reflected signal 36b in the FIG. 1 example.
- Volumetric flow rate equals fluid velocity times cross-sectional area, so the flow rate of the fluids 40a, b can also be readily determined.
- a similar analysis can be performed for each section of the wellbore 12, enabling a contribution to the flow from each set of perforations 42a, b to be determined. Since the acoustic velocity V a in the fluids in the wellbore 12 can be readily determined, a fluid composition contribution of the fluids 40a, b flowing into the individual sections of the wellbore 12 can also be inferred.
- Equation 4 yields a negative number for the velocity
- V f this is an indication that the fluid is flowing in an opposite direction to that assumed when applying values to the variables in Equations 1-4.
- the principles of this disclosure are applicable no matter whether a fluid flows with or in an opposite direction to a signal 36a generated by the signal generator 34, and no matter whether a fluid flows with or in an opposite direction to a reflected signal 36b.
- the reflected pulses 38 can return to the source location, and flow along the wellbore 12 can be determined as described above. If the reflected pulses 38 do not return to the source location, then flow velocity at the source location can be determined from the velocities of the pressure pulses 18 propagating away from the source
- FIG. 2 is a representative plot showing a position of a pressure pulse 18 (and its reflections) repeatedly
- Pulse velocity is proportional to the slope or
- FIG. 3 is a representative plot of the pulse velocity as a function of time (the derivative of FIG 2).
- the pulse velocities in the fluid composition 40a and in the commingled fluid compositions 40a, b can be readily determined.
- the acoustic velocity V a in each fluid composition 40a, b can be readily determined from Equation (3)
- the velocities V f of the fluid composition 40a and commingled fluid compositions 40a, b can be readily determined from Equation (4).
- the acoustic velocity V a in a fluid composition depends on the fluids in the composition and the compliance of the pipe walls or conduit walls containing the fluid (such as, the casing 14 in the FIG. 1 example). Because the pipe walls or conduit walls are not infinitely stiff, the speed of sound in the system is reduced in a quantifiable way. (see, e.g., Robert McKee and Eugene “Buddy” Broerman, "Acoustics in Pumping Systems", 25 th International Pump User Symposium ( 2009 ) ) .
- the fluids in the composition (for example, an oil/water ratio) can be readily estimated.
- the pipe In order to infer the composition of the fluid (oil, water, or the fractions of oil and water), the pipe
- Pipe compliance is very important. Pipe compliance can reduce the speed of sound in the pipe by as little as a few percent all the way up to 50 percent or more.
- Pipe compliance of a steel pipe is caused by not having infinitely stiff walls. It causes the acoustic wave
- FIG. 4 is a plot of acoustic pressure along a non- flowing test well taken with an installed optical waveguide connected to a DAS system. Multiple up and down reflections are observed. Slopes of the V-shaped traces depicted in FIG. 4 are indicative of the acoustic velocity V a of the well fluid. The absolute values of the upward and downward velocities should be equal as the well was not flowing.
- the FIG. 4 data was generated downhole during a
- An acoustic pulse resulted from a pressure differential across a ball (plug) opening a
- Flow rates at multiple different locations in a well can be readily determined.
- Acoustic velocities in different fluid compositions at different locations in the well can also be determined.
- the method can comprise: transmitting an acoustic signal (such as the pressure pulse 18) through at least one fluid composition 40a, b in a well; detecting velocities V u , V d of the acoustic signal in both opposite directions along an optical signal
- the optical waveguide 22 in the well, the optical waveguide 22 being included in a distributed acoustic sensing system 20; and determining an acoustic velocity V a in the fluid composition based on the velocities of the acoustic signal.
- the distributed acoustic sensing system 20 may detect coherent Rayleigh backscattering along the optical waveguide 22.
- the transmitting step can include propagating at least one pressure pulse 18 through the fluid composition 40a, b.
- the detecting step can include detecting at least one reflection of the pressure pulse 18.
- the transmitting step can include transmitting the acoustic signal through multiple fluid compositions 40a, b in the well.
- the determining step can include determining the acoustic velocity V a in each of the multiple fluid
- compositions 40a, b are identical to compositions 40a, b.
- Determining the acoustic velocity V a in the fluid composition 40a, b can include compensating for pipe
- the distributed acoustic sensing system 20 can indicate acoustic energy as distributed along the optical waveguide 22.
- the distributed acoustic sensing system 20 may include an interrogator 24 which detects coherent Rayleigh
- Another well flow velocity measurement method described above can comprise: propagating at least one pressure pulse 18 through at least one fluid composition 40a, b in a well; detecting a velocity of the pressure pulse 18 along an optical waveguide 22 in the well, the optical waveguide being included in a distributed acoustic sensing system 20; and determining an acoustic velocity V a in the fluid
- composition based on the velocity of the pressure pulse.
- the detecting step can include detecting the velocity of the pressure pulse 18 in both opposite directions along the optical waveguide 22.
- the propagating step can include propagating the pressure pulse 18 through multiple fluid compositions 40a, b in the well.
- the system 10 can include a pressure pulse generator 30 which propagates at least one pressure pulse 18 through at least one fluid composition 40a, b in a well, and a distributed acoustic sensing system 20 which detects coherent Rayleigh backscattering along an optical waveguide 22 in the well, whereby a velocity of the pressure pulse in the well is determined.
- a pressure pulse generator 30 which propagates at least one pressure pulse 18 through at least one fluid composition 40a, b in a well
- a distributed acoustic sensing system 20 which detects coherent Rayleigh backscattering along an optical waveguide 22 in the well, whereby a velocity of the pressure pulse in the well is determined.
- the system 10 may include a processor 34 which
- structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa.
Abstract
Description
Claims
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/748,720 US20140202240A1 (en) | 2013-01-24 | 2013-01-24 | Flow velocity and acoustic velocity measurement with distributed acoustic sensing |
PCT/US2014/010682 WO2014116424A1 (en) | 2013-01-24 | 2014-01-08 | Flow velocity and acoustic velocity measurement with distributed acoustic sensing |
Publications (3)
Publication Number | Publication Date |
---|---|
EP2909440A1 true EP2909440A1 (en) | 2015-08-26 |
EP2909440A4 EP2909440A4 (en) | 2016-07-20 |
EP2909440B1 EP2909440B1 (en) | 2019-06-26 |
Family
ID=51206669
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
EP14743240.5A Active EP2909440B1 (en) | 2013-01-24 | 2014-01-08 | Flow velocity and acoustic velocity measurement with distributed acoustic sensing |
Country Status (4)
Country | Link |
---|---|
US (1) | US20140202240A1 (en) |
EP (1) | EP2909440B1 (en) |
CA (1) | CA2891596A1 (en) |
WO (1) | WO2014116424A1 (en) |
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US10247840B2 (en) * | 2013-01-24 | 2019-04-02 | Halliburton Energy Services, Inc. | Optical well logging |
US20140219056A1 (en) * | 2013-02-04 | 2014-08-07 | Halliburton Energy Services, Inc. ("HESI") | Fiberoptic systems and methods for acoustic telemetry |
US10808521B2 (en) | 2013-05-31 | 2020-10-20 | Conocophillips Company | Hydraulic fracture analysis |
US9880048B2 (en) | 2013-06-13 | 2018-01-30 | Schlumberger Technology Corporation | Fiber optic distributed vibration sensing with wavenumber sensitivity correction |
US20160230541A1 (en) * | 2013-09-05 | 2016-08-11 | Shell Oil Company | Method and system for monitoring fluid flux in a well |
GB201513867D0 (en) | 2015-08-05 | 2015-09-16 | Silixa Ltd | Multi-phase flow-monitoring with an optical fiber distributed acoustic sensor |
CA2987721C (en) * | 2015-08-31 | 2022-02-08 | Halliburton Energy Services, Inc. | Methods and systems employing a flow prediction model that is a function of perforation cluster geometry, fluid characteristics, and acoustic activity |
US20170260839A1 (en) * | 2016-03-09 | 2017-09-14 | Conocophillips Company | Das for well ranging |
US10095828B2 (en) | 2016-03-09 | 2018-10-09 | Conocophillips Company | Production logs from distributed acoustic sensors |
US10890058B2 (en) | 2016-03-09 | 2021-01-12 | Conocophillips Company | Low-frequency DAS SNR improvement |
US10920581B2 (en) | 2016-06-30 | 2021-02-16 | Shell Oil Company | Flow velocity meter and method of measuring flow velocity of a fluid |
US10295385B2 (en) | 2016-06-30 | 2019-05-21 | Hach Company | Flow meter with adaptable beam characteristics |
US10161770B2 (en) | 2016-06-30 | 2018-12-25 | Ott Hydromet Gmbh | Flow meter with adaptable beam characteristics |
CA3027267A1 (en) * | 2016-06-30 | 2018-01-04 | Shell Internationale Research Maatschappij B.V. | Flow velocity meter and method of measuring flow velocity of a fluid |
US10408648B2 (en) | 2016-06-30 | 2019-09-10 | Hach Company | Flow meter with adaptable beam characteristics |
EP3619560B1 (en) | 2017-05-05 | 2022-06-29 | ConocoPhillips Company | Stimulated rock volume analysis |
US11255997B2 (en) | 2017-06-14 | 2022-02-22 | Conocophillips Company | Stimulated rock volume analysis |
US11352878B2 (en) | 2017-10-17 | 2022-06-07 | Conocophillips Company | Low frequency distributed acoustic sensing hydraulic fracture geometry |
WO2019191106A1 (en) | 2018-03-28 | 2019-10-03 | Conocophillips Company | Low frequency das well interference evaluation |
AU2019262121B2 (en) | 2018-05-02 | 2023-10-12 | Conocophillips Company | Production logging inversion based on DAS/DTS |
WO2019224567A1 (en) * | 2018-05-22 | 2019-11-28 | Total Sa | Apparatus for measuring fluid flow in a well, related installation and process |
US11480029B2 (en) * | 2019-09-23 | 2022-10-25 | Baker Hughes Oilfield Operations Llc | Autonomous inflow control device for live flow monitoring |
US11802783B2 (en) | 2021-07-16 | 2023-10-31 | Conocophillips Company | Passive production logging instrument using heat and distributed acoustic sensing |
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GB2362462B (en) * | 1997-05-02 | 2002-01-23 | Baker Hughes Inc | A method of monitoring chemical injection into a surface treatment system |
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US7134320B2 (en) * | 2003-07-15 | 2006-11-14 | Cidra Corporation | Apparatus and method for providing a density measurement augmented for entrained gas |
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US9546548B2 (en) * | 2008-11-06 | 2017-01-17 | Schlumberger Technology Corporation | Methods for locating a cement sheath in a cased wellbore |
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GB201103479D0 (en) * | 2011-03-01 | 2011-04-13 | Qinetiq Ltd | Conduit monitoring |
WO2013019529A2 (en) * | 2011-07-29 | 2013-02-07 | Shell Oil Company | Method for increasing broadside sensitivity in seismic sensing system |
GB201116816D0 (en) * | 2011-09-29 | 2011-11-09 | Qintetiq Ltd | Flow monitoring |
US10247840B2 (en) * | 2013-01-24 | 2019-04-02 | Halliburton Energy Services, Inc. | Optical well logging |
US20140204712A1 (en) * | 2013-01-24 | 2014-07-24 | Halliburton Energy Services, Inc. | Downhole optical acoustic transducers |
US9222828B2 (en) * | 2013-05-17 | 2015-12-29 | Halliburton Energy Services, Inc. | Downhole flow measurements with optical distributed vibration/acoustic sensing systems |
-
2013
- 2013-01-24 US US13/748,720 patent/US20140202240A1/en not_active Abandoned
-
2014
- 2014-01-08 CA CA2891596A patent/CA2891596A1/en not_active Abandoned
- 2014-01-08 WO PCT/US2014/010682 patent/WO2014116424A1/en active Application Filing
- 2014-01-08 EP EP14743240.5A patent/EP2909440B1/en active Active
Also Published As
Publication number | Publication date |
---|---|
EP2909440A4 (en) | 2016-07-20 |
CA2891596A1 (en) | 2014-07-31 |
US20140202240A1 (en) | 2014-07-24 |
EP2909440B1 (en) | 2019-06-26 |
WO2014116424A1 (en) | 2014-07-31 |
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