U.S. patent application number 13/748720 was filed with the patent office on 2014-07-24 for flow velocity and acoustic velocity measurement with distributed acoustic sensing.
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 John L. MAIDA, JR., Etienne M. SAMSON, Neal G. SKINNER, Christopher L. STOKELY.
Application Number | 20140202240 13/748720 |
Document ID | / |
Family ID | 51206669 |
Filed Date | 2014-07-24 |
United States Patent
Application |
20140202240 |
Kind Code |
A1 |
SKINNER; Neal G. ; et
al. |
July 24, 2014 |
FLOW VELOCITY AND ACOUSTIC VELOCITY MEASUREMENT WITH DISTRIBUTED
ACOUSTIC SENSING
Abstract
A well flow velocity measurement method can include transmitting
an acoustic signal through at least one fluid composition in a
well, detecting velocities of the acoustic signal in both opposite
directions along an optical waveguide in the well, the optical
waveguide being included in a distributed acoustic sensing system,
and determining an acoustic velocity in the fluid composition based
on the velocities of the acoustic signal. Another well flow
velocity measurement method can include propagating at least one
pressure pulse through at least one fluid composition in a well,
detecting a velocity of the pressure pulse along an optical
waveguide in the well, the optical waveguide being included in a
distributed acoustic sensing system, and determining an acoustic
velocity in the fluid composition based on the velocity of the
pressure pulse.
Inventors: |
SKINNER; Neal G.;
(Lewisville, TX) ; SAMSON; Etienne M.; (Cypress,
TX) ; STOKELY; Christopher L.; (Houston, TX) ;
MAIDA, JR.; John L.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
51206669 |
Appl. No.: |
13/748720 |
Filed: |
January 24, 2013 |
Current U.S.
Class: |
73/152.32 |
Current CPC
Class: |
E21B 47/135 20200501;
E21B 47/107 20200501 |
Class at
Publication: |
73/152.32 |
International
Class: |
E21B 47/10 20060101
E21B047/10 |
Claims
1. A well flow velocity measurement method, comprising:
transmitting an acoustic signal through at least one fluid
composition in a well; detecting velocities of the acoustic signal
in both opposite directions along an optical waveguide in the well,
the optical waveguide being included in a distributed acoustic
sensing system; and determining an acoustic velocity in the fluid
composition based on the velocities of the acoustic signal.
2. The method of claim 1, wherein the distributed acoustic sensing
system detects coherent Rayleigh backscattering along the optical
waveguide.
3. The method of claim 1, wherein the transmitting further
comprises propagating at least one pressure pulse through the fluid
composition.
4. The method of claim 3, wherein the detecting further comprises
detecting at least one reflection of the pressure pulse.
5. The method of claim 1, wherein the transmitting further
comprises transmitting the acoustic signal through multiple fluid
compositions in the well.
6. The method of claim 5, wherein the determining further comprises
determining the acoustic velocity in each of the multiple fluid
compositions.
7. The method of claim 1, wherein the distributed acoustic sensing
system indicates acoustic energy along the optical waveguide.
8. The method of claim 1, wherein the distributed acoustic sensing
system includes an interrogator which detects coherent Rayleigh
backscattering in the optical waveguide.
9. The method of claim 1, wherein the transmitting further
comprises generating the acoustic signal at a location between the
earth's surface and a bottom of the well, the acoustic signal
propagating in the opposite directions from the location.
10. The method of claim 1, wherein the transmitting further
comprises applying an impact to a tubular string.
11. The method of claim 1, wherein determining the acoustic
velocity in the fluid composition further comprises compensating
for pipe compliance.
12. A well flow velocity measurement system, comprising: a pressure
pulse generator which propagates at least one pressure pulse
through at least one fluid composition in a well; and a distributed
acoustic sensing system which detects coherent Rayleigh
backscattering along an optical waveguide in the well, whereby a
velocity of the pressure pulse in the well is determined.
13. The system of claim 12, further comprising a computer which
determines an acoustic velocity in the fluid composition based on
the velocity of the pressure pulse.
14. The system of claim 12, wherein the velocity of the pressure
pulse in both opposite directions along the optical waveguide is
determined.
15. The system of claim 12, wherein the distributed acoustic
sensing system detects at least one reflection of the pressure
pulse.
16. The system of claim 12, wherein the pressure pulse is
propagated through multiple fluid compositions in the well.
17. The system of claim 16, wherein an acoustic velocity in each of
the multiple fluid compositions is determined.
18. The system of claim 12, wherein the distributed acoustic
sensing system indicates acoustic energy along the optical
waveguide.
19. The system of claim 12, wherein the pressure pulse generator
applies an impact to a tubular string.
20. The system of claim 12, wherein the pressure pulse generator
propagates the pressure pulse in opposite directions from a
location in the well.
21. A well flow velocity measurement method, comprising:
propagating at least one pressure pulse through at least one fluid
composition in a well; detecting a velocity of the pressure pulse
along an optical waveguide in the well, the optical waveguide being
included in a distributed acoustic sensing system; and determining
an acoustic velocity in the fluid composition based on the velocity
of the pressure pulse.
22. The method of claim 21, wherein the detecting further comprises
detecting the velocity of the pressure pulse in both opposite
directions along the optical waveguide.
23. The method of claim 21, wherein the distributed acoustic
sensing system detects coherent Rayleigh backscattering along the
optical waveguide.
24. The method of claim 21, wherein the detecting further comprises
detecting at least one reflection of the pressure pulse.
25. The method of claim 21, wherein the propagating further
comprises propagating the pressure pulse through multiple fluid
compositions in the well.
26. The method of claim 25, wherein the determining further
comprises determining the acoustic velocity in each of the multiple
fluid compositions.
27. The method of claim 21, wherein the distributed acoustic
sensing system indicates acoustic energy along the optical
waveguide.
28. The method of claim 21, wherein the distributed acoustic
sensing system includes an interrogator which detects coherent
Rayleigh backscattering in the optical waveguide.
29. The method of claim 21, wherein the propagating further
comprises generating the acoustic signal at a location between the
earth's surface and a bottom of the well, the acoustic signal
propagating in opposite directions from the location.
30. The method of claim 21, wherein the propagating further
comprises applying an impact to a tubular string.
31. The method of claim 21, wherein determining the acoustic
velocity in the fluid composition further comprises compensating
for pipe compliance.
Description
BACKGROUND
[0001] This disclosure relates generally to equipment utilized and
operations performed in conjunction with a subterranean well and,
in an example described below, more particularly provides for flow
velocity and acoustic velocity measurement with distributed
acoustic sensing.
[0002] It is beneficial to be able to determine characteristics of
fluids entering a wellbore, and flow rates of those fluids, so that
decisions relating to production of the fluids can be better
informed. For example, if it is known that an unacceptably large
flow rate of an undesired fluid is entering the wellbore at a
certain location, a decision may be made to restrict or prevent the
undesired fluid from entering the wellbore.
[0003] Therefore, it will be appreciated that advancements are
continually needed in the arts of determining fluid compositions
and flow rates in wells. Such advancements may be used in
production, injection, stimulation, conformance, or other types of
well operations.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] FIG. 1 is a representative partially cross-sectional view of
a well system and associated method which can embody principles of
this disclosure.
[0005] FIG. 2 is a representative plot of pressure pulse location
versus time.
[0006] FIG. 3 is a representative plot of pressure pulse velocity
versus time.
[0007] FIG. 4 is a representative plot of acoustic pulse location
versus time.
DETAILED DESCRIPTION
[0008] Representatively illustrated in FIG. 1 is a well flow
velocity measurement system 10 and associated method which 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.
[0009] This disclosure provides unique techniques for determining
velocities of fluid flows in wells, and for determining
characteristics of the fluids. These techniques can be used to
determine flow rates, acoustic velocities and compositions of the
various fluids which flow through a wellbore 12.
[0010] In the FIG. 1 example, the wellbore 12 is generally vertical
and is lined with casing 14 and cement 16. However, in other
examples, the wellbore 12 may be generally horizontal or inclined,
and may be uncased or open hole, at least in an area of
interest.
[0011] A pressure pulse 18 is transmitted through the wellbore 12.
The pressure pulse 18 may be transmitted from the earth's surface,
or from another location in the well. For example, a pressure pulse
generator 30 may be used to produce positive and/or negative
pressure pulses, which propagate through the fluids in the wellbore
12.
[0012] Pressure pulses can be positive where a compressed air or
nitrogen gun is used to dump a pre-charged volume of gas into the
wellbore 12. Alternatively, pressurized well fluids may be dumped
into an evacuated chamber to generate a negative pressure pulse.
Furthermore, flow exiting a well may be modulated by a choke or
valve at the surface to generate either positive or negative
pulses, or both.
[0013] Apparatus and methods for transmitting such pressure pulses
18 are described in U.S. Pat. Nos. 5,754,495 and 6,321,838,
although other types of pressure pulse generators may be used, if
desired. A preferred pressure pulse generator is the HalSonics.TM.
system marketed by Halliburton Energy Services, Inc. of Houston,
Tex. USA.
[0014] A pressure pulse can also be generated by striking a
structure in the well, such as a tubular string, the casing 14,
etc. When the structure is impacted, a pressure wave develops in
contents of the structure and propagates away from a location of
the impact. A mechanism could, for example, deliver a hammer impact
driven by differential pressure, an electromagnetic solenoid, or
other mechanical actuator.
[0015] In other examples, the pressure pulses 18 could be generated
by detonating a series of explosive or other exothermic devices in
the well. Thus, the scope of this disclosure is not limited to any
particular manner of generating the pressure pulses 18.
[0016] Note that it is not necessary for the pressure pulses 18 to
be generated at or near the earth's surface. In some examples, the
pressure pulses 18 could be generated at or near a bottom of the
wellbore 12, at some location between the surface and the bottom of
the wellbore, etc. If the pressure pulses 18 are generated at a
location between the surface and the bottom of the wellbore 12,
then the pulses can travel in opposite directions via the wellbore
from the location where they were generated.
[0017] The pressure pulses 18 are detected by means of a sensor
located in the well. In this example, the sensor comprises an
optical waveguide 22 (such as, an optical fiber or ribbon), which
may be part of a cable including one or more optical waveguides,
electrical conductors, hydraulic conduits, etc. The sensor is
preferably part of a distributed acoustic sensing (DAS) system 20,
which is capable of detecting acoustic energy as distributed along
an optical waveguide 22.
[0018] In the technique known to those skilled in the art as
distributed acoustic sensing (DAS), acoustic energy distributed
along the optical waveguide 22 can be measured by detecting
coherent Rayleigh backscattering in the waveguide. In this manner,
the pressure pulses 18 and their reflections can be effectively
tracked as they travel along the waveguide 22 in the well.
[0019] The DAS system 20 of FIG. 1 comprises surface optics,
electronics and software, commonly known to those skilled in the
art as an interrogator 24, and the optical waveguide 22. The
optical waveguide 22 may be installed in the wellbore 12, inside or
outside of the casing 14 or other tubulars, optionally in the
cement 16 surrounding the casing, etc.
[0020] The interrogator 24 launches light into the optical
waveguide 22 (e.g., from an infrared laser or other light source
26). A detector 28 detects the light returned via the same optical
waveguide 22. The DAS system 20 uses measurement of backscattered
light (e.g., coherent Rayleigh backscattering) to detect the
acoustic energy along the waveguide 22.
[0021] 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.
[0022] The interrogator 24 and/or the pressure pulse generator 30
may be controlled via a control system 32, for example, including
at least a processor 34 and memory 36. Signal processing is used to
segregate the waveguide 22 into an array of individual
"microphones" or acoustic sensors, typically corresponding to 1-10
meter segments of the waveguide.
[0023] The waveguide 22 may be housed in a metal tubing or control
line and positioned in the wellbore 12. In some examples, the
waveguide 22 may be in cement surrounding the casing 14, in a wall
of the casing or other tubular, suspended in the wellbore 12, in or
attached to a tubular, etc. The scope of this disclosure is not
limited to any particular placement of the waveguide 22.
[0024] The pressure pulse 18 is reflected back through the wellbore
12, and the reflected pressure pulse 38 is also detected by the DAS
system 20. Thus, the DAS system 20 detects the propagation of the
pressure pulse 18 and the reflected pressure pulse 38 as they
displace through the wellbore 12.
[0025] The pressure pulse 18 may be reflected off of a bottom of
the well, off of a plug or other obstruction in the wellbore 12, or
at a fluid/air or fluid/metal interface at or near the surface. In
addition, other changes in acoustic impedance can cause the
pressure pulse 18 to be reflected. Such changes in acoustic
impedance can include changes in acoustic velocity due to changes
in fluid composition in the wellbore 12, changes in casing 14
diameter, etc. The scope of this disclosure is not limited to any
particular manner of producing the reflected pressure pulse 38.
[0026] Using the principles of this disclosure, flow velocity,
V.sub.f and acoustic velocity, V.sub.a of fluid compositions in the
wellbore 12 can be readily determined. If flow velocity is known, a
volumetric flow rate can be readily calculated by multiplying the
flow velocity by flow area.
[0027] The acoustic velocity V.sub.a in a fluid composition depends
on the fluids in the composition and a compliance of a pipe or
conduit containing the fluid composition. If one knows the acoustic
velocity of the fluid composition, the fluids in the composition
(for example, an oil/water ratio) can be readily estimated.
[0028] In the FIG. 1 example, two sets of perforations 42a,b are
depicted in the casing 14, so that respective fluid compositions
40a,b are produced into the wellbore 12. Below the bottom
perforations 42a, no flow enters the well. Between the perforations
42a,b, only the fluid composition 40a is present in the wellbore
12. Above the upper perforations 42b, the fluid compositions 40a,b
are commingled.
[0029] In the FIG. 1 example, the pressure pulse 18 is generated at
the surface, which causes an acoustic wave or signal to travel from
the surface through the wellbore 12 with velocity V.sub.o (in this
case, opposing the direction of flow of the fluids 40a,b). When the
pulse 18 encounters the bottom of the well, it is reflected back
toward the surface with velocity V.sub.w. (in this case, with the
direction of flow of the fluids 40a,b).
[0030] The reflected pulse 38 may return to the surface and be
reflected again through the wellbore 12. With the optical waveguide
22 installed in the well and connected to the DAS interrogator 24,
it is possible to observe the propagation of the pulses 18, 38, and
it may be possible to observe multiple round trips of a pressure
pulse.
[0031] Reflections will occur whenever there is a change in
acoustic impedance. For fluids in pipe, such changes occur, for
example, when an end of the pipe is blocked by a plug, when the
inner diameter of the pipe changes, or if the pipe terminates
inside another pipe with a larger diameter, etc. Amplitudes and
signs of reflected pulses are readily calculated, for example, as
detailed in Kinsler, L. E., et al., Fundamentals of Acoustics,
(1982, John Wiley & Sons, Inc.).
[0032] As the pressure pulse or acoustic wave propagates in either
direction, it decreases in amplitude due to losses, and spreads out
due to dispersion. Although the wave may be detected moving back
and forth through the wellbore 12 for an extended period of time,
it is advantageous to measure the velocity of wave propagation
early on while the wave amplitude is relatively high and its pulse
width is relatively narrow. However, the flow property measurement
techniques described here depend on pulse velocity, not pulse
amplitude.
[0033] Velocities of the pressure pulses 18 and their reflections
38 can be readily determined using the DAS interrogator 24, 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 40a,b can
be determined, as well as a velocity of the commingled fluids
through the wellbore 12.
[0034] In the FIG. 1 example, for a section of the wellbore 12
above the upper perforations 42b:
V.sub.w=V.sub.a+V.sub.f (1)
and:
V.sub.o=V.sub.a-V.sub.f (2)
[0035] where V.sub.w is the velocity of a signal traveling with the
flow of fluid (in the FIG. 1 example, the reflected signal 38),
V.sub.o is the velocity of a signal traveling opposite the flow of
fluid (in the FIG. 1 example, the generated signal 18), V.sub.a is
the acoustic velocity in the commingled fluids 40a,b, and V.sub.f
is the velocity of the fluids through the wellbore 12. Solving the
above linear equations yields:
V.sub.a=(V.sub.w+V.sub.o)/2 (3)
[0036] and, thus, the acoustic velocity V.sub.a is simply the
average of the velocities of the generated signal 36a and the
reflected signal 36b in the FIG. 1 example.
[0037] In addition:
V.sub.f=(V.sub.w+V.sub.o)/2-V.sub.o=V.sub.w-(V.sub.w+V.sub.o)/2
(4)
[0038] gives the velocity V.sub.f of the fluids 40a,b through the
wellbore 12. Volumetric flow rate equals fluid velocity times
cross-sectional area, so the flow rate of the fluids 40a,b can also
be readily determined.
[0039] A similar analysis can be performed for each section of the
wellbore 12, enabling a contribution to the flow from each set of
perforations 42a,b to be determined. Since the acoustic velocity
V.sub.a in the fluids in the wellbore 12 can be readily determined,
a fluid composition contribution of the fluids 40a,b flowing into
the individual sections of the wellbore 12 can also be
inferred.
[0040] If Equation 4 yields a negative number for the velocity
V.sub.f, 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.
[0041] If, as mentioned above, the pressure pulses 18 are generated
between the surface and the bottom of the wellbore 12, then the
reflected pulses 38 can return to the source location, and flow
along the wellbore 12 can be determined as described above. If the
reflected pulses 38 do not return to the source location, then flow
velocity at the source location can be determined from the
velocities of the pressure pulses 18 propagating away from the
source location.
[0042] FIG. 2 is a representative plot showing a position of a
pressure pulse 18 (and its reflections) repeatedly traversing the
wellbore 12. Note that different portions of the plot have
respective different slopes, depending on whether the pulse is
traveling through only the fluid composition 40a, or through the
commingled fluid compositions 40a,b. The change in slope is caused
by changes in flow velocity from combining two or more flows, as
well as changes in the composition of the fluids (e.g., due to
mixing multiple flow streams).
[0043] Pulse velocity is proportional to the slope or derivative of
pulse position with respect to time. FIG. 3 is a representative
plot of the pulse velocity as a function of time (the derivative of
FIG. 2).
[0044] Thus, the pulse velocities in the fluid composition 40a and
in the commingled fluid compositions 40a,b can be readily
determined. Using this data, the acoustic velocity V.sub.a in each
fluid composition 40a,b can be readily determined from Equation
(3), and the velocities V.sub.f of the fluid composition 40a and
commingled fluid compositions 40a,b can be readily determined from
Equation (4).
[0045] Note that the upward and downward velocities are different
at any position along the wellbore 12 in which there is flow. This
can be explained by examining Equations (1) and (2), and noting a
sign difference for V.sub.f, indicating that for a given flow rate
and acoustic velocity V.sub.a, the pulse velocity V.sub.w of the
reflected signal 38 is always greater than the pulse velocity
V.sub.o of the generated signal 18 at any measurement point in the
wellbore 12, for producing wells. For injection wells, this would
be reversed.
[0046] The acoustic velocity V.sub.a in a fluid composition depends
on the fluids in the composition and the compliance of the pipe
walls or conduit walls containing the fluid (such as, the casing 14
in the FIG. 1 example). Because the pipe walls or conduit walls are
not infinitely stiff, the speed of sound in the system is reduced
in a quantifiable way. (see, e.g., Robert McKee and Eugene "Buddy"
Broerman, "Acoustics in Pumping Systems", 25.sup.th International
Pump User Symposium (2009)).
[0047] 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.
[0048] 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 a few percent all the way up to 50 percent or
more.
[0049] 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.
[0050] FIG. 4 is a plot of acoustic pressure along a non-flowing
test well taken with an installed optical waveguide connected to a
DAS system. Multiple up and down reflections are observed. Slopes
of the V-shaped traces depicted in FIG. 4 are indicative of the
acoustic velocity V.sub.a of the well fluid. The absolute values of
the upward and downward velocities should be equal as the well was
not flowing.
[0051] The FIG. 4 data was generated downhole during a fracturing
operation. An acoustic pulse resulted from a pressure differential
across a ball (plug) opening a fracturing sleeve. An acoustic wave
travels from 250 m to about 400 m and back toward the surface,
where it reflects at 250 m.
[0052] It may now be fully appreciated that the above disclosure
provides significant advancements to the arts of determining fluid
compositions and flow rates in wells. Flow rates at multiple
different locations in a well can be readily determined. Acoustic
velocities in different fluid compositions at different locations
in the well can also be determined.
[0053] A well flow velocity measurement method is provided to the
art by the above disclosure. In one example, the method can
comprise: transmitting an acoustic signal (such as the pressure
pulse 18) through at least one fluid composition 40a,b in a well;
detecting velocities V.sub.u, V.sub.d of the acoustic signal in
both opposite directions along an optical waveguide 22 in the well,
the optical waveguide 22 being included in a distributed acoustic
sensing system 20; and determining an acoustic velocity V.sub.a in
the fluid composition based on the velocities of the acoustic
signal.
[0054] The distributed acoustic sensing system 20 may detect
coherent Rayleigh backscattering along the optical waveguide
22.
[0055] The transmitting step can include propagating at least one
pressure pulse 18 through the fluid composition 40a,b. The
detecting step can include detecting at least one reflection of the
pressure pulse 18.
[0056] The transmitting step can include transmitting the acoustic
signal through multiple fluid compositions 40a,b in the well. The
determining step can include determining the acoustic velocity
V.sub.a in each of the multiple fluid compositions 40a,b.
[0057] Determining the acoustic velocity V.sub.a in the fluid
composition 40a,b can include compensating for pipe compliance.
[0058] The distributed acoustic sensing system 20 can indicate
acoustic energy as distributed along the optical waveguide 22.
[0059] The distributed acoustic sensing system 20 may include an
interrogator 24 which detects coherent Rayleigh backscattering in
the optical waveguide 22.
[0060] Another well flow velocity measurement method described
above can comprise: propagating at least one pressure pulse 18
through at least one fluid composition 40a,b in a well; detecting a
velocity of the pressure pulse 18 along an optical waveguide 22 in
the well, the optical waveguide being included in a distributed
acoustic sensing system 20; and determining an acoustic velocity
V.sub.a in the fluid composition based on the velocity of the
pressure pulse.
[0061] The detecting step can include detecting the velocity of the
pressure pulse 18 in both opposite directions along the optical
waveguide 22.
[0062] The propagating step can include propagating the pressure
pulse 18 through multiple fluid compositions 40a,b in the well.
[0063] A well flow velocity measurement system 10 is also described
above. In one example, the system 10 can include a pressure pulse
generator 30 which propagates at least one pressure pulse 18
through at least one fluid composition 40a,b in a well, and a
distributed acoustic sensing system 20 which detects coherent
Rayleigh backscattering along an optical waveguide 22 in the well,
whereby a velocity of the pressure pulse in the well is
determined.
[0064] The system 10 may include a processor 34 which determines an
acoustic velocity V.sub.a in the fluid composition 40a,b based on
the velocity of the pressure pulse 18.
[0065] 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.
[0066] 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.
[0067] 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.
[0068] 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.
[0069] 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."
[0070] 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.
* * * * *