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WO2014088786A1 - Calibrage de système de détection acoustique de puits - Google Patents

Calibrage de système de détection acoustique de puits Download PDF

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Publication number
WO2014088786A1
WO2014088786A1 PCT/US2013/070455 US2013070455W WO2014088786A1 WO 2014088786 A1 WO2014088786 A1 WO 2014088786A1 US 2013070455 W US2013070455 W US 2013070455W WO 2014088786 A1 WO2014088786 A1 WO 2014088786A1
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WO
WIPO (PCT)
Prior art keywords
acoustic
acoustic signals
along
optical waveguide
calibrating
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.)
Ceased
Application number
PCT/US2013/070455
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English (en)
Inventor
Christopher L. Stokely
David A. Barfoot
Neal G. Skinner
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
Priority date (The priority date 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 date listed.)
Filing date
Publication date
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Priority to CA2886449A priority Critical patent/CA2886449C/fr
Publication of WO2014088786A1 publication Critical patent/WO2014088786A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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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
    • E21B47/12—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 examples described below, more particularly provides for calibration of a well acoustic sensing system.
  • An optical distributed acoustic sensor (DAS) system uses an optical waveguide, such as an optical fiber, as a distributed sensor to detect acoustic waves that vibrate the waveguide. This sensing is performed by detecting
  • Changes in the backscattered light can indicate not only the presence of acoustic waves, but also certain characteristics of the acoustic waves.
  • the waveguide For example, if the waveguide is positioned outside of casing in a wellbore, the intensity of acoustic waves originating in the casing and impinging on the
  • waveguide outside of the casing can vary significantly along the waveguide, depending on changes in the casing thickness, changes in cement outside the casing, etc. Additionally, this variation in the characteristics of the acoustic waves which impinge on the waveguide makes it difficult to
  • 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 partially cross-sectional view of another example of the well system and method.
  • FIG. 3 is a representative plot of measured acoustic intensity data as a function of well depth and time, and indicates abrupt changes in intensity where well features change abruptly.
  • FIG. 4 is a representative schematic view of an
  • FIG. 5 is a representative flowchart for a method of mitigating fading using the polarization controller.
  • FIG. 6 is a representative partially cross-sectional view of another example of the system and method, in which a seismic source at a surface location and a three-axis geophone are used for calibration.
  • FIG. 7 is a representative partially cross-sectional view of another example of the system and method, in which an acoustic source in an offset well and a three-axis geophone are used for calibration.
  • FIG. 1 Representatively illustrated in FIG. 1 is a system 10 for use with a well, and an associated method, which system and method can embody principles of this disclosure.
  • an active sound source or sources are housed within an object (a ball, a cylinder, etc.), which is dropped, injected or lowered by cable into a wellbore for the purpose of calibrating an optical distributed acoustic sensor previously installed in a well.
  • the object (s) may also be used to control downhole devices (such as valves, etc.) and/or to plug perforations .
  • downhole devices such as valves, etc.
  • plug perforations There are various vibration speakers, vibrating
  • acoustic transducers e.g., flextensional SONAR transducers, etc.
  • acoustic sources are well known to those skilled in the art and, thus, are not described further here.
  • the distributed acoustic sensor In one example, the distributed acoustic sensor
  • a calibration uses a measurement of a power of acoustic signals at several acoustic frequencies, as well as an extent of the acoustic signals. The calibration will ideally be done over the entirety of the acoustic sensor, or at least in a specific wellbore area of interest.
  • a measurement of the intensity of the sound energy provides the acoustic sensitivity as a function of position along the distributed acoustic sensor.
  • a measurement of the extent of the acoustic signal along the acoustic sensor provides a well location dependent point spread function (e.g., blurring function, blurring kernel, etc.) of acoustic waves as detected by the sensor.
  • Spatial blurring can result from an acoustic sensor at a particular location picking up acoustic waves which originate at multiple locations. That is, a measurement of acoustic power at a specific point in a well is comprised of sounds far away from this specific location. A calibration method to account for this effect is proposed here. A calibration measurement of the acoustic point spread
  • spatial blurring function (spatial blurring function, impulse response, etc.) would allow the acoustic signals to be spatially
  • Yet another calibration factor for distributed acoustic sensing can be determined from measuring an echo-response (i.e., an echo-response (i.e., an echo-response (i.e., an echo-response (i.e., an echo-response (i.e., an echo-response (i.e., an echo-response (i.e., an echo-response (i.e., an echo-response)
  • Enhancement factor which is a measure of the amount the echo has been reduced or attenuated.
  • the sounds can be emitted as continuous single- frequency tones, continuous dual tone multiple frequency (DTMF, similar to what is used for pushbutton telephones), continuous multiple-frequency tones, continuous wide
  • the sounds can also be emitted as pulsed single-frequency tones, pulsed dual tone multiple frequency (DTMF, similar to what is used for pushbutton telephones), pulsed multiple-frequency tones, pulsed wide spectrum tones pulsed white noise, pulsed colored noise, pulsed swept-frequency waveforms, pulsed pseudorandom waveforms, or other pulsed complex waveforms.
  • DTMF pulsed dual tone multiple frequency
  • the sounds can be transmitted in synchrony.
  • the sounds can be transmitted at different volumes at each location.
  • the scope of this disclosure is not limited to any
  • the FIG. 1 example provides for in-situ calibration of an optical acoustic sensor used to measure acoustic energy.
  • the sensor comprises a distributed acoustic sensing (DAS) system, which is capable of detecting acoustic energy as distributed along an optical waveguide.
  • DAS distributed acoustic sensing
  • the sensor comprises surface electronics and software, commonly known to those skilled in the art as an interrogator, and the optical waveguide.
  • the optical waveguide may be installed in a wellbore, inside or outside of casing or other tubulars, optionally in cement surrounding a casing, etc.
  • the interrogator launches light into the optical waveguide (e.g., from an infrared laser), and the DAS system uses measurement of backscattered light (e.g., coherent Rayleigh backscattering) to detect the acoustic energy along the waveguide.
  • Signal processing is used to segregate the waveguide into an array of individual "microphones" or acoustic sensors, typically corresponding to 1-10 meter segments of the waveguide.
  • the waveguide may be housed in a metal tubing or control line and positioned in a wellbore.
  • the waveguide may be in cement surrounding a casing, in a wall of the casing or other tubular, suspended in the wellbore, in or attached to a tubular, etc.
  • the scope of this disclosure is not limited to any particular placement of the waveguide.
  • a sensitivity of the waveguide to acoustic energy can depend significantly on how the waveguide is installed in the well, and on local variations (such as, cement
  • acoustic source may comprise an object which is released, injected or lowered into the wellbore using an electric wireline, a slickline, a wellbore tractor, etc .
  • the DAS sensor can measure the acoustic sensitivity (e.g., the acoustic coupling factor or gain factor) as a function of acoustic frequency, and as a function of position along the waveguide.
  • the acoustic sensitivity e.g., the acoustic coupling factor or gain factor
  • Another embodiment is to measure the cumulative power only as a function of position along the waveguide.
  • the measurement of the gain per DAS channel allows for a gain normalization scale factor to be applied at each location.
  • This gain scale factor can be either frequency dependent or not.
  • the calibrating technique can include measuring the phase of the acoustic signal along the optical waveguide. Measured phase or phase inversion is related to either stretching or compression of the optical waveguide.
  • the acoustic source is
  • acoustic source preferably has an accurate clock to make this measurement.
  • the sound emitted from the acoustic source can also travel along the wellbore and acoustically illuminate other sections of the waveguide, thus allowing determination of the point spread function as a function of acoustic
  • the measurement of the acoustic point spread function allows the acoustic field to be deblurred using any of a number of deblurring methodologies, such as, the Wiener deblurring filter, regularized deblurring filter, Lucy- Richardson deblurring algorithm, blind deconvolution
  • Fading can be caused by several different effects, with polarization effects being a predominant cause.
  • the calibration can be done by averaging out the occasional fading effects by collecting sufficient data over a longer time. Additionally, by oversampling spatially, the calibration data for faded channels may be ignored and the calibration of adjacent non-faded channels used instead for those that are faded.
  • a polarization controller 48 is placed in series with an optical source 50 of the device 26 to adjust the polarization of the light being launched into the optical waveguide 22. Backscattered light is detected by an optical receiver 52.
  • the relative backscattered optical power from each channel will change.
  • the optical signal power from the channel being currently calibrated is optimized until an acceptable signal to noise ratio for the channel being calibrated is obtained.
  • Use of polarization maintaining fiber optic cables can also be employed to mitigate polarization fading, etc.
  • the object which emits the acoustic signals can be injected into the wellbore during a
  • the object could, for example, be a ball, dart or plug used to actuate one or more valves for selectively communicating between the wellbore and an earth formation penetrated by the wellbore.
  • the calibration procedure can be part of the stimulation operation, instead of separate therefrom.
  • the object can be lowered into the wellbore using a wireline, slickline or wellbore tractor. This procedure could be performed separately as needed, or as part of another operation (such as, a wireline logging operation) .
  • FIG. 1 depicts an example in which an acoustic source 12 is conveyed into a wellbore 14 by means of a cable 16
  • the wellbore 14 in this example is lined with casing 18 and cement 20, but in other examples the wellbore could be uncased or open hole.
  • casing is used to indicate a protective wellbore lining. Casing may be made up of
  • Casing may be segmented or continuous. Casing may be made of metals, composites or other materials.
  • an optical waveguide 22 is positioned external to the casing 18, and in the cement 20.
  • the waveguide 22 may be attached externally to the casing 18.
  • the waveguide 22 could be positioned in a wall of the casing 18, in an interior of the casing, or in any other location.
  • one section of the casing 18 has a greater thickness than adjacent sections. This can cause acoustic signals transmitted through the casing 18 to be more
  • the waveguide 22 detects a lower intensity of the acoustic signals at that location .
  • variations in temperature, etc. can also be compensated for in the calibration procedure.
  • the scope of this disclosure is not limited to compensation for any particular type of variation .
  • the acoustic source 12 is displaced to various different locations along the waveguide 22, and the acoustic source transmits a predetermined acoustic signal 28 at the different locations.
  • the acoustic source 12 may transmit the acoustic signal continuously while the source is being displaced along the waveguide 22, or the acoustic signal could be separately transmitted at the respective separate locations.
  • the acoustic signal 28 may comprise a single or multiple acoustic frequencies, certain
  • the acoustic signal 28 may be transmitted at a single or multiple power levels.
  • the scope of this disclosure is not limited to any particular type of acoustic signal(s) 28 transmitted by the acoustic source 12.
  • the acoustic source 12 is dropped or injected into the well, such as, during a fracturing or other stimulation operation .
  • the acoustic source 12 emits the acoustic signal 28 as it displaces through a tubular string 30 in the wellbore 14.
  • a valve 32 is included in the tubular string 30 for
  • the acoustic source 12 may comprise a ball, plug or dart which, when received in the valve 32, allows the valve to be operated to permit or prevent such
  • the acoustic source 12 serves at least two purposes: enabling calibration of the DAS system 24, and enabling operation of the valve 32. In this manner, the DAS system 24 can be calibrated while the stimulation operation proceeds. In other examples, the acoustic source 12 could be used to plug perforations 36, or to perform any other function.
  • FIGS. 1 & 2 examples Although only one acoustic source 12 is depicted in each of the FIGS. 1 & 2 examples, it will be appreciated that any number of acoustic sources may be used. Multiple acoustic sources 12 could be displaced along the waveguide 22 simultaneously or separately. The acoustic sources 12 could each transmit the same predetermined acoustic signal 28, or different acoustic signals could be transmitted by respective different acoustic sources.
  • FIG. 3 an example plot of measured acoustic intensity data as a function of well depth and time is representatively illustrated. Note that, in the plot abrupt changes in intensity are indicated, for example, where well features change abruptly.
  • the presence of the thicker casing 18, a packer, or other discontinuities can be causes of the abrupt changes in intensity.
  • Use of the calibration techniques described above in conjunction with the acoustic source 12 can eliminate or at least significantly reduce the abrupt changes in acoustic intensity as depicted in the FIG. 3 plot.
  • waveguide 22 as a distributed acoustic sensor, multiple individual acoustic sensors may alternatively (or
  • multiple multiplexed fiber Bragg gratings could be used as discreet acoustic sensors 40 (see FIG. 1) distributed along the waveguide 22.
  • the calibration techniques described herein may be used to calibrate the measurements made using the distributed acoustic sensors 40.
  • the calibration techniques described herein may also be used to calibrate measurements made using the distributed acoustic sensors 40, even if the sensors are not optical sensors.
  • a fiber channel is a sensor that produces a single "value,” but the sensor actually responds to energy propagating in different orientations or directions simultaneously.
  • a three-component (x, y, z) geophone can be used as a reference in a calibration
  • vibration energy in the x, y, and z directions can be separated out to determine what the fiber's response is to vibrations that are oriented in the x, y, and z axis directions separately.
  • the x, y, and z directions can be any three orthogonal directions as long as the orientation is known during calibration.
  • the calibration could help in determining the polarization of the shear wave components generated by a microseismic event, the orientation (azimuth) of the fracture (which is a very important piece of information) could be determined.
  • each channel is preferably corrected or normalized based on a calibration .
  • Stoneley waves (or tube waves) travel along the walls of the borehole and are a noise source in vertical seismic profiling.
  • the effect of Stoneley waves is subtracted out of a recorded signal before stacking when doing a vertical seismic profiling application. If Stoneley waves could be generated at a wellhead or using a downhole source designed to generate that kind of wave, we could see how each channel responds and this will enable us able to compensate for them in vertical seismic profiling or other applications .
  • another calibration method can include the use of a remote vibratory or impulse seismic source 12, and preferably, a calibrated reference receiver 42 (such as a three-axis geophone) placed adjacent to the distributed acoustic sensor (such as the optical waveguide 22 or sensors 40).
  • a calibrated reference receiver 42 such as a three-axis geophone
  • the seismic source can be located either on the surface (as depicted in FIG. 6), or in a nearby well (as depicted in FIG. 7).
  • a calibrated seismic receiver 42 accelerometer, geophone, hydrophone, etc., for example a three-axis geophone, is optionally lowered into the well containing the distributed acoustic sensor to the depth of the channel being
  • the seismic source located at the surface or a nearby well is energized to emit seismic energy ( P-wave, S- wave, etc.) to be received by the DAS sensor. Both the DAS sensor and geophone receive substantially the same energy.
  • the DAS sensor uses the receiver 42 as a reference, the DAS sensor
  • the seismic source 12 is placed near a wellhead 44, such that a seismic wave is sent vertically down the length of the well and longitudinally along the length of the DAS sensor.
  • the seismic source is located a significant distance away from the wellhead 44 so that the seismic energy is oriented mostly horizontally. In a deviated or horizontal well, the direction of travel of the seismic energy relative to the wellbore 14 would be altered or reversed based on the layout of the wellbore.
  • the seismic source 12 is lowered into a neighboring well 46.
  • the seismic source may generate S-waves or P-waves to provide a multicomponent calibration of the DAS cable (e.g., optical waveguide 22) based on the type of wave.
  • the cross-well calibration case may be particularly important for micro-seismic detection during hydraulic fracturing operations where the DAS cable may be located in an
  • the seismic source is lowered into the well to be fractured to emit seismic energy (P- wave, S-wave, etc.) into the formation.
  • the DAS cable receives the seismic energy in the observation well, along with a calibration geophone to provide the calibration data.
  • acoustic sensitivity of the DAS system 24 can be compensated for by displacing the acoustic source 12 along the optical waveguide 22 or other distributed acoustic sensors 40, with the acoustic source transmitting the predetermined acoustic signal 28 at different locations along the sensors. In this manner, the output of the DAS system 24 is calibrated.
  • a method of calibrating an optical distributed acoustic sensing system 24 comprises receiving predetermined acoustic signals 28 along an optical waveguide 22 or other distributed acoustic sensors 40 positioned proximate a well, and calibrating the optical distributed acoustic sensing system 24 based on the received predetermined acoustic signals 28.
  • the method can include displacing at least one acoustic source 12 adjacent the optical waveguide 22.
  • the displacing can include displacing the acoustic source 12 through a wellbore 14.
  • the acoustic source 12 preferably transmits the
  • predetermined acoustic signals 28 at multiple locations along the optical waveguide 22.
  • the receiving step can include determining a power, power spectral density, phase, and/or extent of the acoustic signals 28 as received along the optical waveguide 22.
  • the calibrating step can include measuring an acoustic sensitivity along the optical waveguide 22.
  • a method of calibrating an optical distributed acoustic sensing system 24 can include
  • a well system 10 is also described above.
  • the well system 10 can comprise an optical
  • distributed acoustic sensing system 24 including an optical waveguide 22 installed in a well and a backscattered light detection and analysis device 26, and at least one acoustic source 12 which transmits predetermined acoustic signals 28 at multiple spaced apart locations along the optical waveguide 22.
  • the backscattered light detection and analysis device 26 compensates an output of the optical distributed acoustic sensing system 24 based on the
  • predetermined acoustic signals 28 as received at the spaced apart locations along the optical waveguide 22.
  • backscattered light detection and analysis device 26 may determine an acoustic sensitivity along the optical
  • the waveguide measure a phase of the acoustic signals along the optical waveguide 22, determine a power spectral density of the acoustic signals as received along the optical waveguide 22, and/or determine an extent of the acoustic signals as received along the optical waveguide 22.
  • a method of calibrating a distributed acoustic sensing system 10 can include receiving predetermined acoustic signals 28 along multiple acoustic sensors 40 (whether or not the sensors are optical sensors, and whether or not the sensors comprise channels of an optical waveguide, such as an optical fiber) distributed proximate a well; and calibrating the optical distributed acoustic sensing system 10 based on the received predetermined acoustic signals 28.
  • the method can include displacing at least one acoustic source 12 adjacent the acoustic sensors 40.
  • the displacing may include displacing the acoustic source 12 through a wellbore 14.
  • the acoustic source 12 may transmit the predetermined acoustic signals 28 at multiple locations along the acoustic sensors.
  • the acoustic source 12 may transmit the predetermined acoustic signals 28 at different amplitudes at each of the multiple locations.
  • the acoustic source 12 may transmit the predetermined acoustic signals 28 in synchrony with an interrogator (such as the device 26 ) .
  • the calibrating step can include
  • the receiving step may include determining a power, a power spectral density, and/or an extent of the acoustic signals 28 as received along the acoustic sensors 40 .
  • the calibrating step can include measuring an acoustic sensitivity along the acoustic sensors 40 .
  • the method can include transmitting the acoustic signals 28 from another well 46 , or from at or near the earth's surface.
  • the method can include transmitting Stoneley waves from at or near a wellhead 44 , or from a downhole location.
  • the receiving step can include receiving the acoustic signals 28 by a three-axis reference sensor (such as receiver 42 ) positioned proximate the distributed acoustic sensors 40 or optical waveguide 22 .
  • a three-axis reference sensor such as receiver 42
  • the calibrating step can include calibrating the distributed acoustic sensing system 24 based on the
  • the three-axis reference sensor may comprise a geophone.
  • the calibrating step can include computing an acoustic point spread function along the sensors 40 for each of multiple source 12 locations.
  • the calibrating can further comprise using the point spread function determined by the computing to deblur acoustic emissions along a wellbore 14 as received by the distributed acoustic sensors 40.
  • structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa.

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  • Engineering & Computer Science (AREA)
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  • Remote Sensing (AREA)
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  • Geochemistry & Mineralogy (AREA)
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Abstract

Cette invention concerne un procédé de calibrage d'un système de détection acoustique répartie, comprenant, selon un mode de réalisation, les étapes consistant à : recevoir des signaux acoustiques prédéterminés le long de capteurs acoustiques répartis à proximité d'un puits et calibrer le système sur la base des signaux acoustiques reçus. Selon un mode de réalisation, ledit procédé de calibrage d'un système de détection acoustique répartie comprend les étapes consistant à : déplacer une source acoustique le long d'un guide d'onde optique positionné à proximité d'un puits, émettre des signaux acoustiques prédéterminés à partir du dispositif acoustique, recevoir les signaux acoustiques avec le guide d'onde, et calibrer le système sur la base des signaux acoustiques reçus. Un système de puits peut comprendre un système de détection acoustique répartie comprenant un guide d'onde installé dans un puis, et un dispositif de détection et d'analyse de lumière rétrodiffusée, ainsi qu'au moins une source acoustique qui émet des signaux acoustiques prédéterminés à des emplacements espacés le long du guide d'onde. Le dispositif selon l'invention compense une sortie du système sur la base des signaux acoustiques tels qu'ils sont reçus aux emplacements le long du guide d'onde.
PCT/US2013/070455 2012-12-04 2013-11-17 Calibrage de système de détection acoustique de puits Ceased WO2014088786A1 (fr)

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Application Number Priority Date Filing Date Title
CA2886449A CA2886449C (fr) 2012-12-04 2013-11-17 Calibrage de systeme de detection acoustique de puits

Applications Claiming Priority (2)

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US13/693,203 2012-12-04
US13/693,203 US20140150523A1 (en) 2012-12-04 2012-12-04 Calibration of a well acoustic sensing system

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