EP2909440B1 - Strömungsgeschwindigkeits- und schallgeschwindigkeitsmessung mit verteilter schallmessung - Google Patents

Strömungsgeschwindigkeits- und schallgeschwindigkeitsmessung mit verteilter schallmessung Download PDF

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Publication number
EP2909440B1
EP2909440B1 EP14743240.5A EP14743240A EP2909440B1 EP 2909440 B1 EP2909440 B1 EP 2909440B1 EP 14743240 A EP14743240 A EP 14743240A EP 2909440 B1 EP2909440 B1 EP 2909440B1
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EP
European Patent Office
Prior art keywords
velocity
pressure pulse
acoustic
well
optical waveguide
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English (en)
French (fr)
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EP2909440A4 (de
EP2909440A1 (de
Inventor
Neal G. Skinner
Etienne M. Samson
Christopher L. Stokely
John L. Maida
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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    • 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

  • a well flow velocity measurement system comprising: a pressure pulse generator configured to propagate at least one pressure pulse through multiple fluid compositions in a well; and a distributed acoustic sensing system configured to detect coherent Rayleigh backscattering along an optical waveguide in the well, whereby a velocity of the pressure pulse in the well is determined.
  • the pressure pulses 18 could be generated by detonating a series of explosive or other exothermic devices in the well.
  • the scope of this disclosure is not limited to any particular manner of generating the pressure pulses 18.
  • DAS distributed acoustic sensing
  • 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 measurement of backscattered light (e.g., coherent Rayleigh backscattering) to detect the acoustic energy along the waveguide 22.
  • 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, suspended in the wellbore 12, in or attached to a tubular, etc. The scope of this disclosure is not limited to any particular placement of the waveguide 22.
  • 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. Between the perforations 42a,b, only the fluid composition 40a is present in the wellbore 12. Above the upper perforations 42b, the fluid compositions 40a,b are commingled.
  • 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 o (in this case, opposing the direction of flow of the fluids 40a,b).
  • V o in this case, opposing the direction of flow 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.
  • V a V w + V o / 2 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.
  • Pipe compliance of a steel pipe is caused by not having infinitely stiff walls. It causes the acoustic wave traveling down the pipe to move slower than it would in a pipe with infinitely stiff walls.
  • 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 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.
  • an acoustic signal such as the pressure pulse 18
  • 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.
  • Determining the acoustic velocity V a in the fluid composition 40a,b can include compensating for pipe compliance.
  • the distributed acoustic sensing system 20 may include an interrogator 24 which detects coherent Rayleigh backscattering in the optical waveguide 22.
  • Another well flow velocity measurement method described above can comprise: propagating at least one pressure pulse 18 through at least one fluid composition 40 a,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 includes propagating the pressure pulse 18 through multiple fluid compositions 40 a,b in the well.
  • the system 10 may include a processor 34 which determines an acoustic velocity V a in the fluid composition 40 a,b based on the velocity of the pressure pulse 18.

Claims (15)

  1. Bohrlochströmungsgeschwindigkeitsmessverfahren, umfassend:
    Übertragen mindestens eines Druckimpulses (18) durch mehrere Fluidzusammensetzungen (40a, 40b) in einem Bohrloch (12) ;
    Erfassen einer Geschwindigkeit des Druckimpulses entlang eines Lichtwellenleiters (22) in dem Bohrloch, wobei der Lichtwellenleiter in einem verteilten Schallmesssystem (20) beinhaltet ist; und
    Bestimmen einer Schallgeschwindigkeit in der Fluidzusammensetzung auf Grundlage der Geschwindigkeit des Druckimpulses.
  2. Verfahren nach Anspruch 1, wobei das Erfassen ferner das Erfassen der Geschwindigkeit des Druckimpulses in beide entgegengesetzten Richtungen entlang des Lichtwellenleiters umfasst.
  3. Verfahren nach Anspruch 1 oder Anspruch 2, wobei das verteile Schallmesssystem eine kohärente Rayleigh-Rückstreuung entlang des Lichtwellenleiters umfasst.
  4. Verfahren nach einem der vorhergehenden Ansprüche, wobei das Erfassen ferner das Erfassen mindestens einer Spiegelung des Druckimpulses umfasst.
  5. Verfahren nach einem der vorhergehenden Ansprüche, wobei das Bestimmen ferner das Bestimmen der Schallgeschwindigkeit in jeder der mehreren Fluidzusammensetzungen umfasst.
  6. Verfahren nach einem der vorhergehenden Ansprüche, wobei das verteilte Schallmesssystem eine Schallenergie entlang des Lichtwellenleiters anzeigt.
  7. Verfahren nach einem der vorhergehenden Ansprüche, wobei das verteile Schallmesssystem eine Abfragevorrichtung beinhaltet, die eine kohärente Rayleigh-Rückstreuung in dem Lichtwellenleiter erfasst.
  8. Verfahren nach einem der vorhergehenden Ansprüche, wobei das Übertragen ferner das Erzeugen des akustischen Signals an einer Position zwischen der Erdoberfläche und einem Boden des Bohrlochs umfasst, wobei das akustische Signal in eine entgegengesetzte Richtung von der Position übertragen wird.
  9. Verfahren nach einem der vorhergehenden Ansprüche, wobei das Übertragen ferner das Aufbringen einer Stoßwirkung auf einen Rohrstrang umfasst.
  10. Verfahren nach einem der vorhergehenden Ansprüche, wobei das Bestimmen der Schallgeschwindigkeit in der Fluidzusammensetzung ferner das Ausgleichen einer Rohrkonformität umfasst.
  11. Verfahren nach einem der vorhergehenden Ansprüche, wobei:
    sich der Druckimpuls als ein akustisches Signal bewegt; und
    das Erfassen von Geschwindigkeiten des akustischen Signals in beide entgegengesetzte Richtungen entlang des Lichtwellenleiters (22) stattfindet.
  12. Bohrlochströmungsgeschwindigkeitsmesssystem, umfassend:
    einen Druckimpulsgenerator (30), der dazu konfiguriert ist, mindestens einen Druckimpuls (18) durch mehrere Fluidzusammensetzungen (40a, 40b) in einem Bohrloch (12) zu übertragen; und
    ein verteiltes Schallmesssystem (20), das dazu konfiguriert ist, eine kohärente Rayleigh-Rückstreuung entlang eines Lichtwellenleiters (22) in dem Bohrloch zu erfassen, wobei eine Geschwindigkeit des Druckimpulses in dem Bohrloch bestimmt wird.
  13. System nach Anspruch 12, wobei:
    ein Computer dazu konfiguriert ist, eine Schallgeschwindigkeit in der Fluidzusammensetzung auf Grundlage der Geschwindigkeit des Druckimpulses zu bestimmen; und/oder
    bei Verwendung des Systems eine Schallgeschwindigkeit in jeder der mehreren Fluidzusammensetzungen bestimmt wird.
  14. System nach Anspruch 12 oder 13, wobei:
    bei Verwendung des Systems die Geschwindigkeit des Druckimpulses in beide entgegengesetzten Richtung entlang des Lichtwellenleiters bestimmt wird; und/oder
    das verteilte Schallmesssystem dazu konfiguriert ist, mindestens eine Spiegelung des Druckimpulses zu erfassen.
  15. System nach einem der Ansprüche 12 bis 14, wobei:
    das verteilte Schallmesssystem dazu konfiguriert ist, eine Schallenergie entlang des Lichtwellenleiters anzugzeigen; und/oder
    der Druckimpulsgenerator dazu konfiguriert ist, eine Stoßwirkung auf einen Rohrstrang (14) aufzubringen; und/oder
    der Druckimpulsgenerator dazu konfiguriert ist, den Druckimpuls in entgegengesetzte Richtungen von einer Position des Bohrlochs zu übertragen.
EP14743240.5A 2013-01-24 2014-01-08 Strömungsgeschwindigkeits- und schallgeschwindigkeitsmessung mit verteilter schallmessung Active EP2909440B1 (de)

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

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EP2909440A1 EP2909440A1 (de) 2015-08-26
EP2909440A4 EP2909440A4 (de) 2016-07-20
EP2909440B1 true EP2909440B1 (de) 2019-06-26

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US (1) US20140202240A1 (de)
EP (1) EP2909440B1 (de)
CA (1) CA2891596A1 (de)
WO (1) WO2014116424A1 (de)

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EP2909440A4 (de) 2016-07-20
CA2891596A1 (en) 2014-07-31
US20140202240A1 (en) 2014-07-24
EP2909440A1 (de) 2015-08-26
WO2014116424A1 (en) 2014-07-31

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