Note: Descriptions are shown in the official language in which they were submitted.
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DOWNHOLE OPTICAL AkxnnvrIc TRANSDUCERS
TECHNICAL FIELD
This disclosure relates generally to equipment utilized
and operations performed in conjunction with a subterranean
well and, in examples described below, more particularly
provides downhole optical acoustic transducers and
associated methods.
BACKGROUND
Acoustic energy may be used for various purposes in a
well. In some well systems, a distributed acoustic sensing
(DAS) system can be used to "listen" to acoustic signals in
a well.
Therefore, it will be appreciated that improvements are
continuously needed in the art of generating acoustic
signals in a well.
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.
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FIG. 2 is a representative partially cross-sectional
view of the system and method, wherein a well logging
assembly is displaced in a wellbore by a conveyance.
FIGS. 3-11 are representative schematic views of an
optical acoustic transducer which may be used in the system
and method of FIGS. 1 & 2, and which can embody the
principles of this disclosure.
FIG. 12 is a representative partially cross-sectional
view of another example of the system and method.
FIG. 13 is a representative schematic view of another
optical acoustic transducer which may be used in the system
and method, and which can embody the principles of this
disclosure.
FIGS. 14 & 15 are representative view of photodiode
arrangements which may be used in the system and method.
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 the FIG. 1 example, a well logging assembly 12 is
conveyed into a wellbore 14 by a conveyance 16. The wellbore
14 is lined with casing 18 and cement 20. Perforations 22
formed through the casing 18 and cement 20 allow fluid 24a,b
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to flow into the wellbore 14 from respective formation zones
26a,b penetrated by the wellbore.
In this example, it is desired to determine a flow rate
of each of the fluids 24a,b into the wellbore 14 from each
of the zones 26a,b. However, in other examples it might be
desired to determine a flow rate of injection fluid from the
wellbore 14 into each of the zones 26a,b. Thus, the scope of
this disclosure is not limited to any particular purpose for
a well operation.
Instead, the principles described herein may be used
for a variety of different purposes, whether or not the
wellbore 14 is lined with casing 18 and cement 20, whether
or not perforations 22 are used to flow fluids 24a,b between
the wellbore and respective zones 26a,b, etc. These details
and others are provided in the FIG. 1 example for purposes
of illustration, but the scope of this disclosure is not
limited to any of the FIG. 1 details.
The well logging assembly 12 may include conventional
logging tools, such as, a casing collar locator 28, a gamma
ray tool 30 and sensors 32 (for example, a pressure sensor
and a temperature sensor). In addition, the well logging
assembly 12 includes a signal generator 34 for generating
one or more acoustic signals 36a in the well.
In some examples, the signals 36a could be generated by
striking the conveyance 16, casing 18 or other structure. A
mechanism could, for example, deliver a hammer impact driven
by differential pressure, an electromagnetic solenoid, or
other mechanical actuator.
In other examples, the signals 36a could be generated
by detonating a series of explosive or other exothermic
devices in the well. Thus, the scope of this disclosure is
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not limited to any particular manner of generating the
signals 36a.
The signals 36a are preferably reflected in the well,
for example, at a fluid/air or fluid/metal interface or any
interface in the well with an abrupt change in acoustic
impedance. Reflected signals 36b travel in the wellbore 14
in a direction opposite to that of the signals 36a generated
by the signal generator 34.
For simplicity of illustration and explanation, FIG. 1
depicts the signals 36a travelling upwardly from the signal
generator 34, and the reflected signals 36b travelling
downwardly in the wellbore 14. However, in practice, the
signals 36a would travel in both directions through the
wellbore 14 from the signal generator 34, and the reflected
signals 36b also travel in both directions, and can be
reflected from any surface or other impedance change.
Acoustic signals 36a can be generated, for example, by
impacting one component against another, by energizing one
or more piezoelectric elements, etc. The scope of this
disclosure is not limited to any particular way of
generating the signals 36a.
As mentioned above, the conveyance 16 is used to convey
the well logging assembly 12 into the well. However, the
conveyance 16 also includes a component of the assembly 12,
in the form of an optical waveguide 38 (such as, a single
and/or multi-mode optical fiber or optical ribbon).
Although only one optical waveguide 38 is depicted in
FIG. 1, any number of optical waveguides may be used, as
desired. In addition, the conveyance 16 could include
various other types of lines, such as, electrical conductors
and fluid conduits. The scope of this disclosure is not
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limited to any particular number, combination, configuration
or arrangement of lines in the conveyance 16.
The conveyance 16 may be in the form of a cable with
suitable strength, temperature resistance, chemical
resistance and protection for the optical waveguide 38. The
cable could comprise stranded cable or cable made from small
diameter (e.g., h in. diameter) metal tubing or control
line, with the optical waveguide 38 inside the line.
In some examples, the conveyance 16 could be in the
form of a coiled tubing (e.g., a substantially continuous
tubular string, typically stored on a reel), with the
optical waveguide 38 positioned inside, in a wall of, and/or
exterior to, the coiled tubing. The scope of this disclosure
is not limited to any particular form of the conveyance 16,
or to any particular position of the optical waveguide 38
with respect to the conveyance.
An optical interrogator 40 is coupled to the optical
waveguide 38. The interrogator 40 includes a light source 42
(such as, an infrared laser) and an optical detector 44
(such as, a photodiode or other photo-detector).
The interrogator 40 is used to determine at least one
parameter as distributed along the optical waveguide 38.
This is accomplished by launching light from the source 42
into the optical waveguide 38 and detecting light
backscattered in the optical waveguide.
In one technique known to those skilled in the art as
distributed acoustic sensing (DAS), acoustic energy
distributed along the optical waveguide 38 can be measured
by detecting coherent Rayleigh backscattering in the
waveguide. In this manner, the signals 36a and their
reflections 36b can be effectively tracked as they travel
along the waveguide 38 in the well.
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In another technique, an array of weak fiber Bragg
gratings or other artificially introduced reflectors can be
used with the optical waveguide 38 to detect acoustic
signals along the waveguide.
Velocities of the signals 36a and their reflections 36b
can be readily determined using the DAS interrogator 40, for
example, by dividing displacement of the signals by elapsed
time. Using this information, with the system 10 configured
as depicted in FIG. 1, an acoustic velocity in the
commingled fluids 24a,b can be determined, as well as a
velocity of the commingled fluids through the wellbore 14.
V, = V, + Vf (1)
and:
V, = V, - Vf (2)
where V, is the velocity of a signal traveling with the
flow of fluid (in the FIG. 1 example, the generated signal
36a), V, is the velocity of a signal traveling opposite the
flow of fluid (in the FIG. 1 example, the reflected signal
36b), V, is the acoustic velocity in the commingled fluids
24a,b, and Vf is the velocity of the fluids through the
wellbore 14. Solving the above linear equations yields:
V, = (4 + V0)/2 (3)
and, thus, the acoustic velocity V, is simply the
average of the velocities of the generated signal 36a and
the reflected signal 36b in the FIG. 1 example. In addition:
Vf = (V,, + V0)/2 ¨ Vo = Vw ¨ (Vw + V0)/2 ( 4 )
gives the velocity Vfof the fluids 24a,b through the
wellbore 14. Volumetric flow rate equals fluid velocity
times cross-sectional area, so the flow rate of the fluids
24a,b can also be readily determined.
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If Equation 4 yields a negative number for the velocity
Vt., this is an indication that the fluid is flowing in an
opposite direction to that assumed when applying values to
the variables in Equations 1-4. The principles of this
disclosure are applicable no matter whether a fluid flows
with or in an opposite direction to a signal 36a generated
by the signal generator 34, and no matter whether a fluid
flows with or in an opposite direction to a reflected signal
36b.
The interrogator 40 can be connected to a control
system 46 (including, for example, a processor 48, memory
50, software, etc.) for controlling operation of the
interrogator, recording measurements, calculating acoustic
velocities and fluid velocities, displaying results, etc.
In the configuration depicted in FIG. 1, the system 10
can be used to determine the flow rate of the commingled
fluids 24a,b, as well as characteristics (e.g., pressure,
temperature, acoustic velocity, etc.) of the commingled
fluids in the wellbore 14. However, by positioning the
assembly 12 below the lower set of perforations 22, as
depicted in FIG. 2, flow rates of each of the fluids 24a,b
can be readily determined. This is so, because the system 10
is capable of detecting the velocities of the signals 36a
and their reflections 36b as distributed along the optical
waveguide 38 in the wellbore 14.
Thus, in a section of the wellbore 14 below the lower
set of perforations 22 (where there is substantially no
flow), the velocities of the signals 36a and their
reflections 36b will be the same and, according to Equation
(3) above, will equal the acoustic velocity 17a in the fluid
present in that section of the wellbore. In a section of the
wellbore 14 between the lower and upper sets of perforations
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22 (where only the fluid 24a flows), the velocity of the
fluid 24a and the acoustic velocity in that fluid can be
readily determined. In a section of the wellbore 14 above
the upper set of perforations 22 (where the commingled
fluids 24a,b flow), the velocity of the commingled fluids
and the acoustic velocity in those fluids can be readily
determined, as described above. Knowing the volumetric flow
rate from the lower set of perforations 22, and the combined
flow rate of the fluids 24a,b, one can readily determine a
contribution to flow from the upper set of perforations via
subtraction.
Therefore, it will be appreciated that, with the well
logging assembly 12 positioned as depicted in FIG. 2,
acoustic velocities and fluid velocities at each location in
the wellbore 14 traversed by the optical waveguide 38 can be
readily determined. This makes it unnecessary to relocate
the assembly 12 to each position in which it is desired to
determine a flow rate (e.g., as is the case with
conventional flowmeters).
Instead, the assembly 12 can simply be positioned so
that the optical waveguide 38 traverses all of the sections
of the wellbore 14 of interest, the signal generator 34 can
be operated to produce the signals 36a (and, consequently,
their reflections 36b), and the interrogator 40 can quickly
be used to measure acoustic energy along the optical
waveguide. This consumes much less time as compared to
conventional well logging techniques and, thus, is much more
economical in practice.
The acoustic velocity V, in a fluid composition depends
on the fluids in the composition and the compliance of the
pipe walls or conduit walls containing the fluid. Because
the pipe walls or conduit walls are not infinitely stiff,
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the speed of sound in the system is reduced in a
quantifiable way. (see Robert McKee and Eugene "Buddy"
Broerman, "Acoustics in Pumping Systems", 25th International
Pump User Symposium (2009)).
If one knows the acoustic velocity of the fluid
composition and the pipe wall compliance(s) (readily
calculated from pipe parameters such as the elasticity
modulus of the steel pipe, the inside pipe diameter and the
pipe wall thickness), the fluids in the composition (for
example, an oil/water ratio) can be readily estimated.
In order to infer the composition of the fluid (oil,
water, or the fractions of oil and water), the pipe
compliance is very important. Pipe compliance can reduce the
speed of sound in the pipe by as little as few percent all
the way up to 50 percent or more.
Pipe compliance of a steel pipe is caused by not having
infinitely stiff walls. It causes the acoustic wave
traveling down the pipe to move slower than it would in a
pipe with infinitely stiff walls.
FIGS. 3-8 illustrate various examples of how, in a
downhole environment (e.g., in the well of FIG. 1, in
another wellbore, etc.), optical energy can be converted to
electrical energy, which can be stored and controllably
released, to generate the acoustic signals 36a. However, it
should be clearly understood that it is not necessary for
the optical energy to be first converted to electrical
energy, and then converted to acoustic energy in the
transducer 34. In other examples, the optical energy could
be converted to thermal energy (e.g., by directing light
transmitted via the optical waveguide 34 onto a black body,
which is thereby heated, etc.), and the thermal energy could
be used to generate the acoustic signals 36a (e.g., using a
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heat engine, such as a Stirling engine). Thus, the scope of
this disclosure is not limited to any particular series of
energy conversion steps in the transducer 34.
FIG. 3 depicts a representative circuit diagram for the
transducer 34. A photodiode 52 is connected to a step up
transformer 54. The photodiode 52 is illuminated with pulsed
light 56 carried downhole over the optical waveguide 38.
Voltage generated in the photodiode 52 from the
incident light 56 is input into the transformer 54, where it
may be stepped up or merely isolated from the photodiode.
Cl, C2, D1 and D2 make up a well-known alternating current
to direct current (AC to DC) voltage doubler 58. DC voltage
Vout across at an output of the voltage doubler 58 will be
roughly twice an AC amplitude output from the transformer
54. If higher voltage is required, the turns-ratio of the
transformer 54 can be altered and/or additional stages of
voltage doublers 58 may be used.
An oscillator 60 is connected to the voltage doubler
58. The oscillator 60 is used to produce a desired acoustic
wave form (amplitude, frequency, etc.) from an electrical to
acoustic transducer 62. The acoustic signals 36 are
propagated from the electrical to acoustic transducer 62 in
the FIG. 3 example.
A suitable electrical to acoustic transducer could
comprise one or more piezoelectric elements, a solenoid
which drives a mass to strike another structure, etc. The
scope of this disclosure is not limited to use of any
particular type of electrical to acoustic transducer.
In FIG. 4, another example of the optical to acoustic
transducer 34 is depicted. In this example, two voltage
doublers 58 (effectively a voltage quadrupler) are used.
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Note that, if a sufficient number of voltage doublers 58 is
used, the step up transformer 54 may not be required.
Indeed, the transformer 54 and the voltage doubler 58
are only two examples of voltage increasers 64 (see FIGS. 6-
9) which may be used to increase a voltage output by the
photodiode 52. The scope of this disclosure is not limited
to use of any particular type of voltage increaser.
There may be circumstances where one would want to
limit the optical signals transmitted via the waveguide 38
that cause the circuit of FIG. 4 to generate Vout. For
example, multiple circuits may be illuminated by a single
optical waveguide 38, and it may be desired to multiplex the
circuits so that one or more selected circuits produce Vout
without the others doing so. FIG. 5 depicts an example of
the transducer 34 which provides security against accidental
operation, and/or allows for multiplexing.
In the FIG. 5 example, an optical filter 66 is
positioned between the light 56 and the photodiode 52. The
filter 66 passes only a narrow range of wavelengths. Only
when the specific range of wavelengths that match the pass
band of the filter 66 are transmitted from the light source
42 will the circuit produce Vout.
In other examples, the photodiode 52 may be selected so
that it generates current only in response to a certain
range of wavelengths. Thus, the scope of this disclosure is
not limited to any particular way of preventing the circuit
from producing Vout when certain preselected wavelengths of
light 56 are not transmitted.
FIG. 5 also depicts an additional capacitor, Cf in
series with a primary winding of the transformer 54, forming
an LC filter with resonance frequency equal to
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radians/second where L is the effective inductance of the
transformer. This filter prevents the flow of current into
the transformer 54 when the pulses illuminating the
photodiode 52 are not at the resonant frequency. Other types
of electric filters and filter topologies may be used to
determine a light 56 pulse repetition rate required to
activate a particular electrical power converter. Thus,
wavelength division multiplexing and/or pulse frequency
multiplexing can be added with only minor changes to the
circuit.
In addition to providing the ability to multiplex
multiple circuits on an optical waveguide and selectively
operate one or more desired circuits independently, the
wavelength or pulse frequency selective circuits described
here may serve as a safety feature. For example, if one
desired to use optical power to trigger an explosive device
in a well (such as, a perforating gun, a seismic charge,
etc.), one could combine features described here, so that
the device would not be detonated, unless light with a
specified wavelength is modulated with a specified frequency
for a specified time period via an optical fiber in the
well.
In the above examples, pulsed optical power is
converted into DC voltage, however, the electrical to
acoustic transducer 62 could instead be operated with short,
high power electrical pulses. In order to generate
electrical pulses, the circuit can be modified as shown in
FIG. 6.
In FIG. 6, a voltage increaser 64 is depicted as
representing any type of voltage increaser. For example, the
voltage doubler 58, the step up transformer 54, any number
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or combination of these and/or other types of voltage
increasers.
Cout is shown to the right of the voltage increaser 64.
The total energy stored in the output capacitor Cout is
- COW VOW
2 Joules. Where Vout is the voltage across Cout,
controlled by the output voltage of the photodiode 52, and
the configuration of the voltage increaser 64.
The transducer 62 to be supplied with electrical power
is connected across Cout through a gas discharge tube (GDT)
68, a device that acts as an open switch until it reaches a
threshold voltage differential, at which time it acts as a
closed switch, dumping the electrical energy stored in Cout
to the transducer 62 (and optionally via the oscillator 60,
as in the FIGS. 3-5 examples). The circuit depicted in FIG.
6 will rapidly deliver the electrical power stored in Gout
to the transducer 62 whenever the voltage across the GDT 68
reaches its threshold. The time to buildup a given threshold
voltage across the GDT 68 will depend on the amplitude and
frequency of the incident pulses of light 56, the size of
capacitor Cout and internal leakage and efficiency of the
circuit components. This can make timing of the delivery of
electrical power through the GDT 68 to the transducer 62
difficult to predict.
This limitation is mitigated by altering the circuit
further as shown in FIG. 7. In this example, the GDC 68 is
replaced by, for example, a thyristor or SCR which are
semiconductor devices which can be thought of as a
switchable diode 70. An SCR is a diode with an additional
gate. When the current flows into the gate, the diode acts
normally, conducting only in the forward biased direction,
however, when current is not injected into the gate, the
diode does not conduct in either direction.
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In order to trigger the circuit shown in FIG. 7 to
supply electrical power to the transducer 62 at a desired,
controllable instant, a brief pulse of triggering light 72
illuminates a trigger photodiode 74. The trigger photodiode
74 generates a brief pulse of current that causes the SCR
(or switchable diode 70) to dump the energy stored in Cout
to the transducer 62. The operating characteristics of an
SCR are such that, even if the trigger pulse light 72 is
turned off, the SCR will conduct until all the energy stored
in Cout is dumped to the transducer 62 (and optionally via
the oscillator 60, as in the FIGS. 3-5 examples).
Other techniques may be used to control how the circuit
is triggered by the triggering light 72. For example, the
triggering light 72 can be controlled or filtered via
similar optical and/or electrical filtering techniques
described above for controlling when voltage is supplied to
the transformer 54 from the photodiode 52. The scope of this
disclosure is not limited to any particular way of
controlling and/or multiplexing the triggering of the
circuit in response to the triggering light 72.
In yet another example depicted in FIG. 8, the SCR is
replaced by a three lead neon tube 76 which can be
considered as a trigger-able GDT. The triggering photodiode
74 is connected such that its output is used to trigger a
gas discharge through the neon tube 76, whereby electrical
power is provided to the transducer 62 (and optionally via
the oscillator 60, as in the FIGS. 3-5 examples).
Referring additionally now to FIG. 9, another example
of the optical acoustic transducer 34 is representatively
illustrated. In this example, the light 56 illuminates an
optical to electrical transducer 78. Voltage produced by the
transducer 78 is input to the voltage increaser 64.
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Increased voltage from the voltage increaser 64 is
input to the electrical to acoustic transducer 62 via the
oscillator 60. Optionally, any of the trigger circuits
depicted in FIGS. 6-8 may be used to control when energy
stored in Cout is dumped to the transducer 62.
The optical to electrical transducer 78 may be any type
of transducer capable of converting optical energy to
electrical energy. The photodiode 52 is one example of a
suitable optical to electrical transducer 78.
Referring additionally now to FIG. 10, the optical to
electrical transducer 78 of FIG. 9 is replaced by an optical
to heat transducer 80 and a thermal to electrical transducer
82. Voltage output by the transducer 82 is input to the
voltage increaser 64.
The optical to thermal transducer 80 may be any type of
transducer capable of converting optical energy to thermal
energy. For example, the light 56 could illuminate a black
body, thereby generating thermal energy.
The thermal to electrical transducer 82 may be any type
of transducer capable of converting heat energy to
electrical energy. For example, a thermopile, thermocouple
or other heat to electrical transducer 82 can receive the
heat generated by the transducer 80 and convert that heat to
electrical energy for input to the voltage increaser 64.
Referring additionally now to FIG. 11, another example
of the optical to acoustic transducer 34 is representatively
illustrated. In this example, heat generated by the optical
to thermal transducer 80 is input to a thermal to mechanical
transducer 84. Mechanical energy is input to a mechanical to
acoustic transducer 86 to generate the signals 36.
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The thermal to mechanical transducer 84 may be any type
of transducer capable of converting heat energy to
mechanical energy. For example, a suitably configured
Stirling engine could be used for the transducer 84.
The mechanical to acoustic transducer 86 may be any
type of transducer capable of utilizing mechanical energy to
generate the acoustic signals 36. For example, mechanical
energy could be used to strike one component against another
component and thereby generate stress waves in structures in
the well, pressure pulses could be generated with pistons or
membranes displaced via mechanical energy, etc.
The acoustic signals 36 could be generated by
detonating small explosive charges. The charges could be
detonated electrically, for example, or they could be
detonated by direct heating as a result of focusing laser
energy from the optical waveguide onto an explosive, such as
a detonator in close proximity to a main charge, etc.
The acoustic signals 36 could be generated by releasing
compressed fluid, or by opening a series of low pressure
chambers downhole.
It will, thus, be appreciated that the optical to
acoustic transducer 34 can be constructed in a variety of
different configurations, and those configurations are not
limited to the examples depicted in FIGS. 3-11. It should
also be appreciated that a wide variety of different
applications for the principles described herein are not
limited to the FIGS. 1 & 2 example of the system 10.
In FIG. 12, another example of the system 10 is
representatively illustrated, in which the optical to
acoustic transducer 34 is positioned in the well external to
a tubular string 88. The tubular string 88 could be, for
example, a production tubing string, a coiled tubing string,
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a completion string, a stimulation string, an injection
string, a work string, a liner, etc.
In other examples, the transducer 34 and/or waveguide
38 could be internal to, or positioned in a wall of, the
tubular string 88. The transducer 34 and/or waveguide 38
could be internal to, external to, or positioned in a wall
of the casing 18, or in the cement 20, etc. The scope of
this disclosure is not limited to any particular location of
the transducer 34 and/or waveguide 38.
The transducer 34 generates the signals 36, which
propagate in opposite directions away from the transducer.
The signals 36 can travel through various structures and
fluids in the well.
The optical waveguide 38 can be used, as described
above, to track the signals 36, and thereby determine
properties of fluid 24 in the well. However, the scope of
this disclosure is not limited to use of the optical
acoustic transducer 34 for determining properties of fluids.
Note that the transducer 34 may be located in any
position with respect to the conveyance 16 or tubular string
88 in the above examples. The transducer 34 could be at any
location along the conveyance 16 or tubular string 88, and
multiple transducers can be spaced apart along the
conveyance or tubular string.
Referring additionally now to FIG. 13, another example
of the optical to acoustic transducer 34 is representatively
illustrated. In this example, the photodiode 52 is part of a
photovoltaic converter 90. A suitable photovoltaic converter
is available from JDSU (e.g., model PPC-XE) of Milpitas,
California USA.
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The voltage increaser 64 in this example can comprise a
DC to DC converter. A suitable DC to DC converter is
available from PICO Electronics, Inc. (e.g., model XA200,
with 200v output) of Pelham, New York USA.
The electrical acoustic transducer 62 in this example
can comprise a piezoelectric actuator. A suitable
piezoelectric actuator is available from MIDE Engineering
(e.g., model QP2OW) of Medford, Massachusetts USA.
A spark gap 92 may be used to control voltage across
the transducer 62. For example, a 150v spark gap is
available from Bourns, Inc. (e.g., model 652-2027-1S-SN-LF)
of Riverside, California USA.
Referring additionally now to FIGS. 14 & 15, techniques
for increasing a voltage or current output of the photodiode
52 in the transducer 34 are representatively illustrated. In
FIG. 14 multiple photodiodes 52 are connected in series, in
order to increase a voltage output, and in FIG. 15 multiple
photodiodes are connected in parallel, in order to increase
a current output, to the voltage increaser 64.
An optical coupler 94 can be used to direct the light
56 to each of the photodiodes 52 in the FIGS. 14 & 15
examples. Any number or arrangement of photodiodes 52 may be
used (e.g., singles, multiples, in series and/or in
parallel), in keeping with the principles of this
disclosure.
It may now be fully appreciated that the above
disclosure provides significant advancements to the art of
generating acoustic signals in wells. In some examples
described above, an optical acoustic transducer 34 is used
to convert optical energy to acoustic energy, for generating
acoustic signals 36 in a well.
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A method of generating an acoustic signal 36 in a
subterranean well is provided to the art by the above
disclosure. In one example, the method can comprise:
converting optical energy to acoustic energy downhole,
thereby transmitting the acoustic signal 36 through a
downhole environment. The downhole environment may include
structures (such as casing 18, cement 20, tubular string 88,
etc.) and/or fluids 24 in the well.
The converting step can include converting the optical
energy to electrical energy downhole. The converting step
can further include illuminating an optical to electrical
transducer 78 with light transmitted via an optical
waveguide 38 downhole.
The converting step can further include converting the
electrical energy to the acoustic energy downhole. The
converting can also comprise converting the electrical
energy to mechanical energy downhole (for example, a
solenoid striker or a motor could convert electrical to
mechanical energy downhole).
The method may include storing the electrical energy
downhole. The method can further include triggering a
release of the electrical energy downhole.
The converting step can include converting the optical
energy to thermal energy downhole. The converting step can
further include converting the thermal energy to the
acoustic energy downhole.
The converting can include converting the thermal
energy to mechanical energy downhole. The converting step
can further include converting the mechanical energy to the
acoustic energy downhole.
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A well system 10 is also described above. In one
example, the system 10 can include an optical acoustic
transducer 34 disposed in the well and coupled to an optical
waveguide 38 in the well. The transducer 34 converts optical
energy transmitted via the optical waveguide 38 to acoustic
energy.
The optical acoustic transducer 34 may comprise an
optical electrical transducer 78 which converts the optical
energy to electrical energy in the well. The optical
electrical transducer 78 can be illuminated with light 56
transmitted via the optical waveguide 38 in the well.
The optical acoustic transducer 34 may comprise an
electrical acoustic transducer 62 which converts the
electrical energy to the acoustic energy in the well.
The electrical energy generated by the optical
electrical transducer 78 may be stored in the well. The
optical acoustic transducer 34 can release the stored
electrical energy in the well.
The optical acoustic transducer 34 may comprise an
optical thermal transducer 80 which converts the optical
energy to thermal energy in the well. The optical acoustic
transducer 34 may further comprise a thermal acoustic
transducer which converts the thermal energy to the acoustic
energy in the well.
The optical acoustic transducer 34 may comprise a
thermal mechanical transducer 84 which converts the thermal
energy to mechanical energy in the well. The optical
acoustic transducer 34 may comprise a mechanical acoustic
transducer 86 which converts the mechanical energy to the
acoustic energy in the well. The combined thermal mechanical
transducer 84 and mechanical acoustic transducer 86 may be
considered a thermal acoustic transducer.
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An optical acoustic transducer 34 for use in a
subterranean well is also described above. In one example,
the optical acoustic transducer 34 includes a means for
converting optical energy transmitted via an optical
waveguide 38 to acoustic energy in the well.
The converting means may comprise an optical electrical
transducer 78 which converts the optical energy to
electrical energy in the well. The optical electrical
transducer 78 can be illuminated with light 56 transmitted
via the optical waveguide 38 in the well.
The converting means may comprise an electrical
acoustic transducer 62 which converts the electrical energy
to the acoustic energy in the well.
The electrical energy generated by the optical
electrical transducer 78 may be stored in the well. The
converting means can release the stored electrical energy in
the well.
The converting means may comprise an optical thermal
transducer 80 which converts the optical energy to thermal
energy in the well. The converting means may further
comprise a thermal acoustic transducer which converts the
thermal energy to the acoustic energy in the well.
The converting means may comprise a thermal mechanical
transducer 84 which converts the thermal energy to
mechanical energy in the well. The converting means may
comprise a mechanical acoustic transducer 86 which converts
the mechanical energy to the acoustic energy in the well.
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.
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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,
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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.
