U.S. patent application number 13/693203 was filed with the patent office on 2014-06-05 for calibration of a well acoustic sensing system.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to David A. BARFOOT, Neal G. SKINNER, Christopher L. STOKELY.
Application Number | 20140150523 13/693203 |
Document ID | / |
Family ID | 50824103 |
Filed Date | 2014-06-05 |
United States Patent
Application |
20140150523 |
Kind Code |
A1 |
STOKELY; Christopher L. ; et
al. |
June 5, 2014 |
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.
Inventors: |
STOKELY; Christopher L.;
(Houston, TX) ; BARFOOT; David A.; (Houston,
TX) ; SKINNER; Neal G.; (Lewisville, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
50824103 |
Appl. No.: |
13/693203 |
Filed: |
December 4, 2012 |
Current U.S.
Class: |
73/1.82 ;
73/152.58 |
Current CPC
Class: |
E21B 47/135
20200501 |
Class at
Publication: |
73/1.82 ;
73/152.58 |
International
Class: |
E21B 47/14 20060101
E21B047/14 |
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.
Description
BACKGROUND
[0001] 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.
[0002] 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.
[0003] 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.
[0004] 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
[0005] FIG. 1 is a representative partially cross-sectional view of
a well system and associated method which can embody principles of
this disclosure.
[0006] FIG. 2 is a representative partially cross-sectional view of
another example of the well system and method.
[0007] 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.
[0008] FIG. 4 is a representative schematic view of an interrogator
having a polarization controller used for fading mitigation.
[0009] FIG. 5 is a representative flowchart for a method of
mitigating fading using the polarization controller.
[0010] 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.
[0011] 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
[0012] 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.
[0013] 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.
[0014] 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.
[0015] 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.
[0016] 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.
[0017] 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.
[0018] 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.
[0019] 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.
[0020] 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.
[0021] 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.
[0022] 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.
[0023] 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.
[0024] 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.
[0025] 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.
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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.
[0030] 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.
[0031] 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.
[0032] 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.
[0033] 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.
[0034] 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.
[0035] 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.
[0036] 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.
[0037] 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).
[0038] 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.
[0039] 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.
[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] 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.
[0045] 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.
[0046] 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.
[0047] 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.
[0048] 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.
[0049] 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.
[0050] 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.
[0051] 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.
[0052] 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.
[0053] 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.
[0054] 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.
[0055] 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.
[0056] 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.
[0057] 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.
[0058] 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.
[0059] 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.
[0060] 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.
[0061] 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.
[0062] 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.
[0063] The acoustic source 12 preferably transmits the
predetermined acoustic signals 28 at multiple locations along the
optical waveguide 22.
[0064] 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.
[0065] The calibrating step can include measuring an acoustic
sensitivity along the optical waveguide 22.
[0066] 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.
[0067] 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.
[0068] 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.
[0069] 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.
[0070] 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.
[0071] 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.
[0072] 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.
[0073] 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.
[0074] The calibrating step can include measuring an acoustic
sensitivity along the acoustic sensors 40.
[0075] The method can include transmitting the acoustic signals 28
from another well 46, or from at or near the earth's surface.
[0076] The method can include transmitting Stoneley waves from at
or near a wellhead 44, or from a downhole location.
[0077] 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.
[0078] 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.
[0079] 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.
[0080] 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.
[0081] 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.
[0082] 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.
[0083] 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.
[0084] 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."
[0085] 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.
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