CALIBRATION OF A WELL ACOUSTIC SENSING SYSTEM

Abstract

A method of calibrating a distributed acoustic sensing system can include receiving predetermined acoustic signals along acoustic sensors distributed proximate a well, and calibrating the system based on the received acoustic signals. A method of calibrating an optical distributed acoustic sensing system can include displacing an acoustic source along an optical waveguide positioned proximate a well, transmitting predetermined acoustic signals from the acoustic source, receiving the acoustic signals with the waveguide, and calibrating the system based on the received acoustic signals. A well system can include a distributed acoustic sensing system including an optical waveguide installed in a well, and a backscattered light detection and analysis device, and at least one acoustic source which transmits predetermined acoustic signals at spaced apart locations along the waveguide. The device compensates an output of the system based on the acoustic signals as received at the locations along the waveguide.

Description

BACKGROUND

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 backscattered light transmitted through the waveguide. Changes in the backscattered light can indicate not only the presence of acoustic waves, but also certain characteristics of the acoustic waves.

Unfortunately, when an optical waveguide is installed in a well, various factors (such as, acoustic couplings and wellbore construction) can influence measured acoustic power as a function of frequency, as well as other characteristics of the acoustic waves which impinge on the optical 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 interpret measurements made by a DAS system.

Thus, it will be appreciated that improvements are continually needed in the art of using distributed acoustic sensing systems in conjunction with subterranean wells. Such improvements could be useful for calibrating well acoustic sensing systems other than DAS systems, for example, well acoustic sensing systems which include arrays of multiplexed point sensors, such as fiber Bragg gratings, or non-optical distributed acoustic sensing systems.

BRIEF DESCRIPTION OF THE DRAWINGS

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 interrogator having a polarization controller used for fading mitigation.

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.

DETAILED DESCRIPTION

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.

However, it should be clearly understood that the 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 disclosure is not limited at all to the details of the system 10 and method described herein and/or depicted in the drawings.

In this example, 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. In the case of dropping or injecting one or more objects with active sound source(s), the object(s) may also be used to control downhole devices (such as valves, etc.) and/or to plug perforations.

There are various vibration speakers, vibrating actuators, and acoustic transducers, e.g., flextensional SONAR transducers, etc., that are capable of actively producing sounds within an object. Such acoustic sources are well known to those skilled in the art and, thus, are not described further here.

In one example, the distributed acoustic sensor 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 function (spatial blurring function, impulse response, etc.) would allow the acoustic signals to be spatially deconvolved, inverted, deblurred, etc., to enhance the sounds heard at only one location in the well. Yet another calibration factor for distributed acoustic sensing can be determined from measuring an echo-response (i.e., an acoustic impulse response) of the well, so that echoes in the well can be removed or reduced as desired. This is typically done using a frequency domain adaptive filter that maximizes a term referred to as the Echo Return Loss 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 spectrum tones, continuous white noise, continuous colored noise, continuously repeating swept-frequency waveforms, continuous pseudorandom waveforms, or other continuously repeating complex waveforms. 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.

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 particular predetermined acoustic signals transmitted by an acoustic source.

If the sounds are transmitted at different volumes at various locations, nonlinearities in the gain response as a function of location in the well can be determined.

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. 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. In some examples, 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 variations, casing variations, presence of other equipment such as packers or cable clamps, temperature variations, presence of gas or liquids in the wellbore, type of fluid in the wellbore or cement, etc.). For example, significant temperature variations along a wellbore can affect the amount of Rayleigh backscattering in the waveguide.

In a calibration procedure described below, these variations can be compensated for by detecting predetermined acoustic signals transmitted along the waveguide by an acoustic source. The 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.

By emitting sound in a controlled manner from the acoustic source, and receiving the resulting acoustic energy along the waveguide, 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. 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.

Another embodiment is to synchronize the sound emissions with a clock so a phase of the signals can be measured as a function of position along the waveguide. 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.

To measure the phase, the acoustic source is synchronized with the clock of the interrogator. The 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 frequency and as a function of position along the wellbore. These parameters (acoustic sensitivity and point spread function) are used to calibrate the DAS system.

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 deblurring algorithm, or Vardi-Lee expectation maximization deblurring algorithm, for example.

Generally, there are a percentage (usually small) of channels of some DAS systems that experience an issue known as “fading,” where the signal-to-noise ratio (SNR) of the channel will be reduced temporarily. This reduction in SNR, may reduce the accuracy of the calibration. 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.

In an additional method representatively illustrated in FIGS. 4 & 5, 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.

By adjusting the polarization of the outgoing light, the relative backscattered optical power from each channel will change. Using an iterative optimization process of adjusting the launch polarization (see FIG. 5), 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.

In one example, the object which emits the acoustic signals can be injected into the wellbore during a fracturing or other stimulation operation. 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. In this manner, the calibration procedure can be part of the stimulation operation, instead of separate therefrom.

In another example, 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 (e.g., wireline, slickline, other type of cable, etc.). 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.

As used herein, the term “casing” is used to indicate a protective wellbore lining. Casing may be made up of tubulars known to those skilled in the art as casing, liner or tubing. Casing may be segmented or continuous. Casing may be made of metals, composites or other materials.

In the FIG. 1 example, 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. In other examples, the waveguide 22 could be positioned in a wall of the casing 18, in an interior of the casing, or in any other location.

Note that 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 attenuated at the thicker section, so that the waveguide 22 detects a lower intensity of the acoustic signals at that location.

It would be desirable to calibrate an output of a DAS system 24 (including the waveguide 22 and an interrogator or backscattered light detection and analysis device 26), so that the output is compensated for such variations. Of course, other types of variations (e.g., variations in fluid types in the wellbore 14, casing 18 and cement 20, 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.

In the calibration procedure, 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.

As mentioned above, the acoustic signal 28 may comprise a single or multiple acoustic frequencies, certain combinations of frequencies, white noise, colored noise, or pseudorandom waveforms. 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.

Referring additionally now to FIG. 2, another example of the system 10 is representatively illustrated. In this example, 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 providing selective communication between an interior of the tubular string 30 and an earth formation 34 penetrated by the wellbore 14. 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 communication.

Thus, in the FIG. 2 example, 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.

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.

Referring additionally now to 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.

Although the examples described herein use the waveguide 22 as a distributed acoustic sensor, multiple individual acoustic sensors may alternatively (or additionally) be used. For example, 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.

One of the issues with conventional DAS systems is that 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. In some examples described below, a three-component (x, y, z) geophone can be used as a reference in a calibration technique, so that 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.

For example, in many seismic applications, it would be desirable to know how the fiber responds to p-waves coming from the side (cross-well) versus longitudinal (along the wellbore). For microseismic detection, it would be desirable to know the response of the fiber to shear or s-waves, including s-waves of different polarizations, because shear waves are a major energy component of microseismic events (typically fractures). If the response of the fiber to horizontally polarized s-waves and vertically polarized s-waves could be separately determined, it would be possible to infer the response to other polarizations. If 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.

Due to the distance and weakness of most microseismic events, it would be desirable to combine the response of many DAS channels using techniques like beamforming in order to see these events. To do beamforming effectively, 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. Preferably, 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.

As representatively illustrated in FIG. 6, 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). The calibrated reference receiver 42 is not required for the methods described herein, but will improve the accuracy of the calibration by accounting for the signal attenuation and distortion effects caused by the formation 34 between the source 12 and the DAS sensor. In this method, 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 calibrated. 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. Using the receiver 42 as a reference, the DAS sensor response to a variety of different signals produced by the seismic source 12, including various amplitude, frequency, and directional variations, can be compared to the receiver response to derive a calibration for the DAS sensor.

For example, in one method 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. In another method, 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.

In the case of a cross-well calibration (as depicted in FIG. 7), 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 observation well nearby the well to receive the fracturing treatment. In this scenario, 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.

It may now be fully appreciated that the above disclosure provides significant advancements to the art of optical distributed acoustic sensing. In examples described above, variations in 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 is described above. In one example, the method 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.

In one example, a method of calibrating an optical distributed acoustic sensing system 24 can include displacing at least one acoustic source 12 along an optical waveguide 22 positioned proximate a well, transmitting predetermined acoustic signals 28 from the acoustic source 12, receiving the predetermined acoustic signals 28 with the optical waveguide 22, and calibrating the optical distributed acoustic sensing system 24 based on the received predetermined acoustic signals 28.

A well system 10 is also described above. In one example, 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.

In this example, 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. The backscattered light detection and analysis device 26 may determine an acoustic sensitivity along the optical 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.

In a broad aspect, it is not necessary for the distributed acoustic sensing system to be “optical,” or for the distributed acoustic sensors to be “optical.” 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 measuring a phase of the acoustic signals 28 along the acoustic sensors 40.

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.

The calibrating step can include calibrating the distributed acoustic sensing system 24 based on the predetermined acoustic signals 28 as detected by the three-axis reference sensor 42. 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.

Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example's features are not mutually exclusive to another example's features. Instead, the scope of this disclosure encompasses any combination of any of the features.

Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used.

It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.

In the above description of the representative examples, directional terms (such as “above,” “below,” “upper,” “lower,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.

The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.”

Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.

Claims

1. A method of calibrating a distributed acoustic sensing system, the method comprising:

receiving predetermined acoustic signals along multiple acoustic sensors distributed proximate a well; and

calibrating the distributed acoustic sensing system based on the received predetermined acoustic signals.

2. The method of claim 1, further comprising displacing at least one acoustic source adjacent the acoustic sensors.

3. The method of claim 2, wherein the displacing further comprises displacing the acoustic source through a wellbore.

4. The method of claim 2, wherein the acoustic source transmits the predetermined acoustic signals at multiple locations along the acoustic sensors.

5. The method of claim 4, wherein the acoustic source transmits the predetermined acoustic signals at different amplitudes at each of the multiple locations.

6. The method of claim 4, wherein the acoustic source transmits the predetermined acoustic signals in synchrony with an interrogator.

7. The method of claim 6, wherein the calibrating further comprises measuring a phase of the acoustic signal along the acoustic sensors.

8. The method of claim 1, wherein the receiving further comprises determining a power of the acoustic signals as received along the acoustic sensors.

9. The method of claim 1, wherein the receiving further comprises determining a power spectral density of the acoustic signals as received along the acoustic sensors.

10. The method of claim 1, wherein the receiving further comprises determining an extent of the acoustic signals as received along the acoustic sensors.

11. The method of claim 1, wherein the calibrating further comprises measuring an acoustic sensitivity along the acoustic sensors.

12. The method of claim 1, further comprising transmitting the acoustic signals from another well.

13. The method of claim 1, further comprising transmitting the acoustic signals from at or near the earth's surface.

14. The method of claim 1, further comprising transmitting Stoneley waves from at or near a wellhead.

15. The method of claim 1, further comprising transmitting Stoneley waves from a downhole location.

16. The method of claim 1, wherein the receiving further comprises receiving the acoustic signals by a three-axis reference sensor positioned proximate the distributed acoustic sensors.

17. The method of claim 16, wherein the calibrating further comprises calibrating the distributed acoustic sensing system based on the predetermined acoustic signals as detected by the three-axis reference sensor.

18. The method of claim 16, wherein the three-axis reference sensor comprises a geophone.

19. The method of claim 1, wherein the calibrating further comprises computing an acoustic point spread function along the sensors for each of multiple source locations.

20. The method of claim 19, wherein the calibrating further comprises using the point spread function determined by the computing to deblur acoustic emissions along a wellbore as received by the distributed acoustic sensors.

21. A method of calibrating an optical distributed acoustic sensing system, the method comprising:

receiving predetermined acoustic signals along an optical waveguide positioned proximate a well; and

calibrating the optical distributed acoustic sensing system based on the received predetermined acoustic signals.

22. The method of claim 21, further comprising displacing at least one acoustic source adjacent the optical waveguide.

23. The method of claim 22, wherein the displacing further comprises displacing the acoustic source through a wellbore.

24. The method of claim 22, wherein the acoustic source transmits the predetermined acoustic signals at multiple locations along the optical waveguide.

25. The method of claim 24, wherein the acoustic source transmits the predetermined acoustic signals at different amplitudes at each of the multiple locations.

26. The method of claim 24, wherein the acoustic source transmits the predetermined acoustic signals in synchrony with an interrogator.

27. The method of claim 26, wherein the calibrating further comprises measuring a phase of the acoustic signals along the optical waveguide.

28. The method of claim 21, wherein the receiving further comprises determining a power of the acoustic signals as received along the optical waveguide.

29. The method of claim 21, wherein the receiving further comprises determining a power spectral density of the acoustic signals as received along the optical waveguide.

30. The method of claim 21, wherein the receiving further comprises determining an extent of the acoustic signals as received along the optical waveguide.

31. The method of claim 21, wherein the calibrating further comprises measuring an acoustic sensitivity along the optical waveguide.

32. The method of claim 21, further comprising transmitting the acoustic signals from another well.

33. The method of claim 21, further comprising transmitting the acoustic signals from at or near the earth's surface.

34. The method of claim 21, further comprising transmitting Stoneley waves from at or near a wellhead.

35. The method of claim 21, further comprising transmitting Stoneley waves from a downhole location.

36. The method of claim 21, wherein the receiving further comprises receiving the acoustic signals by a three-axis reference sensor positioned proximate the optical waveguide.

37. The method of claim 36, wherein the calibrating further comprises calibrating the optical distributed acoustic sensing system based on the predetermined acoustic signals as detected by the three-axis reference sensor.

38. The method of claim 36, wherein the three-axis reference sensor comprises a geophone.

39. The method of claim 21, wherein the calibrating further comprises computing an acoustic point spread function along the optical waveguide for each of multiple source locations.

40. The method of claim 39, wherein the calibrating further comprises using the point spread function determined by the computing to deblur acoustic emissions along a wellbore as received by the optical waveguide.

41. A method of calibrating an optical distributed acoustic sensing system, the method comprising:

displacing at least one acoustic source along an optical waveguide positioned proximate a well;

transmitting predetermined acoustic signals from the acoustic source;

receiving the predetermined acoustic signals with the optical waveguide; and

calibrating the optical distributed acoustic sensing system based on the received predetermined acoustic signals.

42. The method of claim 41, wherein the displacing further comprises displacing the acoustic source through a wellbore.

43. The method of claim 41, wherein the acoustic source transmits the predetermined acoustic signals at multiple locations along the optical waveguide.

44. The method of claim 43, wherein the acoustic source transmits the predetermined acoustic signals at different volumes at each of the multiple locations.

45. The method of claim 43, wherein the acoustic source transmits the predetermined acoustic signals in synchrony with an interrogator.

46. The method of claim 45, wherein the calibrating further comprises measuring a phase of the acoustic signals along the optical waveguide.

47. The method of claim 41, wherein the receiving further comprises determining a power of the acoustic signals as received along the optical waveguide.

48. The method of claim 41, wherein the receiving further comprises determining a power spectral density of the acoustic signals as received along the optical waveguide.

49. The method of claim 41, wherein the receiving further comprises determining an extent of the acoustic signals as received along the optical waveguide.

50. The method of claim 41, wherein the calibrating further comprises measuring an acoustic sensitivity along the optical waveguide.

51. The method of claim 41, wherein the transmitting further comprises transmitting the acoustic signals from another well.

52. The method of claim 41, wherein the transmitting further comprises transmitting the acoustic signals from at or near the earth's surface.

53. The method of claim 41, wherein the transmitting further comprises transmitting Stoneley waves from at or near a wellhead.

54. The method of claim 41, wherein the transmitting further comprises transmitting Stoneley waves from a downhole location.

55. The method of claim 41, wherein the receiving further comprises receiving the acoustic signals by a three-axis reference sensor positioned proximate the optical waveguide.

56. The method of claim 55, wherein the calibrating further comprises calibrating the optical distributed acoustic sensing system based on the predetermined acoustic signals as detected by the three-axis reference sensor.

57. The method of claim 55, wherein the three-axis reference sensor comprises a geophone.

58. The method of claim 41, wherein the calibrating further comprises computing an acoustic point spread function along the acoustic waveguide for each of multiple source locations.

59. The method of claim 58, wherein the calibrating further comprises using the point spread function determined by the computing to deblur acoustic emissions along a wellbore as received by the optical waveguide.

60. A well system, comprising:

an optical distributed acoustic sensing system including an optical waveguide installed in a well, and a backscattered light detection and analysis device; and

at least one acoustic source which transmits predetermined acoustic signals at multiple spaced apart locations along the optical waveguide,

wherein the backscattered light detection and analysis device compensates an output of the optical distributed acoustic sensing system based on the predetermined acoustic signals as received at the spaced apart locations along the optical waveguide.

61. The system of claim 60, wherein the acoustic source is displaced adjacent the optical waveguide.

62. The system of claim 60, wherein the acoustic source is displaced through a wellbore.

63. The system of claim 60, wherein the backscattered light detection and analysis device determines a power of the predetermined acoustic signals as received along the optical waveguide.

64. The system of claim 60, wherein the acoustic source transmits the predetermined acoustic signals at different volumes at each of the multiple locations.

65. The system of claim 60, wherein the acoustic source transmits the predetermined acoustic signals in synchrony with an interrogator.

66. The system of claim 65, wherein the backscattered light detection and analysis device measures a phase of the acoustic signals along the optical waveguide.

67. The system of claim 60, wherein the backscattered light detection and analysis device determines a power spectral density of the acoustic signals as received along the optical waveguide.

68. The system of claim 60, wherein the backscattered light detection and analysis device determines an extent of the acoustic signals as received along the optical waveguide.

69. The system of claim 60, wherein the backscattered light detection and analysis device measures an acoustic sensitivity along the optical waveguide.

70. The system of claim 60, wherein the acoustic signals comprise Stoneley waves.

71. The system of claim 60, wherein the acoustic signals are received by a three-axis reference sensor positioned proximate the optical waveguide.

72. The system of claim 71, wherein the backscattered light detection and analysis device compensates the output of the optical distributed acoustic sensing system based on the predetermined acoustic signals as detected by the three-axis reference sensor.

73. The system of claim 71, wherein the three-axis reference sensor comprises a geophone.

74. A method of calibrating a distributed acoustic sensing system, the method comprising:

receiving predetermined acoustic signals along multiple acoustic sensors distributed proximate a well; and

computing an acoustic point spread function along the sensors for each of multiple source locations.

75. The method of claim 74, further comprising, using the point spread function determined by the computing to deblur acoustic emissions along a wellbore as received by the distributed acoustic sensors.