U.S. patent application number 16/545678 was filed with the patent office on 2021-02-25 for multiphase flow metering system for horizontal well compartments.
The applicant listed for this patent is Saudi Arabian Oil Company. Invention is credited to Moataz Abu AlSaud, Brett W. Bouldin, Ahmed Y. Bukhamseen, Robert John Turner.
Application Number | 20210055146 16/545678 |
Document ID | / |
Family ID | 1000005381756 |
Filed Date | 2021-02-25 |
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United States Patent
Application |
20210055146 |
Kind Code |
A1 |
Bukhamseen; Ahmed Y. ; et
al. |
February 25, 2021 |
MULTIPHASE FLOW METERING SYSTEM FOR HORIZONTAL WELL
COMPARTMENTS
Abstract
A method of measuring two or more fluid phases of in a downhole
well bore that comprises measuring a flow of each of the two or
more phases at respective offtake points at which the two or more
phases are unmixed within the well bore. In certain
implementations, the well bore is inclined at 20 degrees or less to
a horizontal axis. Each of the two or more phases can flow at a
rate to achieve low Reynolds numbers in a laminar flow regime.
Inventors: |
Bukhamseen; Ahmed Y.;
(Dammam, SA) ; Bouldin; Brett W.; (Dhahran,
SA) ; Turner; Robert John; (Dhahran, SA) ;
AlSaud; Moataz Abu; (Khobar, SA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Saudi Arabian Oil Company |
Dhahran |
|
SA |
|
|
Family ID: |
1000005381756 |
Appl. No.: |
16/545678 |
Filed: |
August 20, 2019 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/10 20130101;
G01F 5/005 20130101; G01F 23/263 20130101; E21B 47/06 20130101 |
International
Class: |
G01F 5/00 20060101
G01F005/00; G01F 23/26 20060101 G01F023/26; E21B 47/10 20060101
E21B047/10; E21B 47/06 20060101 E21B047/06 |
Claims
1. A method of measuring two or more fluid phases of in a downhole
well bore comprising: receiving a stratified flow of the two or
more fluid phases via respective ports; immersing two or more level
sensors within each of the two more fluid phases. maintaining a
level of an interface between the two or more phases in a range by
operation of valves at the respective ports to ensure that at least
one port is within one of the two or more stratified fluid phases;
and measuring the stratified flow of each of the two or more phases
at the respective ports at which the two or more phases are unmixed
within the well bore.
2. The method of claim 1, wherein the well bore is inclined at 20
degrees or less to a horizontal axis.
3. The method of claim 1, wherein the each of the two or more
phases flow at a rate to achieve low Reynolds numbers in a laminar
or near laminar flow regime.
4. The method of claim 1, wherein the two or more phases mix
downstream from the offtake points.
5. (canceled)
6. The method of claim 1, further comprising measuring the pressure
of the two or more phases across the respective ports.
7. (canceled)
8. The method of claim 1, further comprising controlling the
opening of the valves to maintain separation of the two or more
flowing phases during an entire production period.
9. The method of claim 8, further comprising determining a flow
rate of the two or more phases based on pressure at the offtake
points according to the equation: Q i = C V i .DELTA. p .rho. i
##EQU00005## In which Qi is the flow rate of the ith phase,
C.sub.Vi is a coefficient related to the properties of the variable
valve of the ith valve, .DELTA.p is a pressure differential
measured at the ith port, .rho..sub.i is the density of the ith
phase, and in which the two or more phases number 1 to i.
10. A system for of measuring two or more fluid phases of in a
downhole well bore comprising: a tube within the well bore having
two or more ports equipped with valves, each port for receiving a
stratified flow of the two or more fluid phases, respectively; two
or more fluid measurement sensors for measuring a parameter
indicative of flow in each one of the two or more phases at
respective offtake points at which the two or more phases are
unmixed within the well bore; two or more level sensors, one of the
two or more level sensors being immersed in each one of the
respective two or more phases; and. an electronic control unit
communicatively coupled to the two or more fluid measurements
sensors and the two or more level sensors and configured to control
the valves of the two or more ports based on data received from the
two or more level sensors to maintain a level of an interface
between the two or more phases in a range by operation of valves at
the respective ports to ensure that at least one port is within one
of the two or more stratified fluid phases.
11. (canceled)
12. (canceled)
13. The system of claim 10, wherein the well bore is inclined at 20
degrees or less to a horizontal axis.
14. The system of claim 13, wherein the inclination of the well
bore and control of the port valves cause the flow of each of the
two or more phases to have low Reynolds numbers in a laminar or
near flow regime.
15. The system of claim 10, wherein the two or more phases mix
downstream from the offtake points.
16. The method of claim 10, wherein the plurality of flow
measurement sensors include pressure sensors.
17. The system of claim 16, wherein one of the pressure sensors is
positioned at one of the two or more ports of the tube, and another
of the pressure sensors is positioned in an annulus surrounding the
tube within the well bore, the pressure sensors together measuring
a pressure drop between the annulus and the tube, across the ports
of the tube.
Description
FIELD OF THE DISCLOSURE
[0001] The present disclosure relates to oil and gas exploration
and production, and, more particularly, relates to a multiphase
flow metering system for a horizontal well compartment and
associated method of multiphase flow metering.
BACKGROUND OF THE DISCLOSURE
[0002] In oil and gas production, it is often useful to measure the
amount of fluid flowing in various parts of the infrastructure. For
example, flow measurement can be used to monitor the performance of
multizonal horizontal wells and the real-time measurement of water
flow, which allows production engineers to plan immediate remedial
action. Multiphase flow is fluid flow that includes two or more
components, referred to as phases. In the oil and gas field, the
multiphase flow typically consists of oil and water, oil and gas,
or oil, gas and water. Measurement of the total mass fluid flow
does not necessarily provide useful information concerning the flow
of each of the distinct phase components, which is often
desired.
[0003] Conventional two-phase flow meters typically use several
sensors and process the sensor data with algorithms to interpret
complex flows. One of the common methods to measure the flow rate
downhole employs a Venturi to measure mass single-phase flow. To
obtain the phase fraction in two-phase flow, the Venturi is coupled
with another sensor to accurately measure density. By design, the
Venturi creates enough pressure drop to generate well-mixed flow.
However, mixing the fluids can create further complications such as
emulsions, erosion, and additional pressure drops. Other techniques
that measure flows by separating or stratifying the phases employ
cumbersome separation devices and are not optimized for sensing and
the phase levels in a horizontal well.
[0004] It would therefore be advantageous to provide a system and
method for multiphase flow metering in a horizontal well
compartment that avoids the complexities of fluid mixing and is
optimized for horizontal wells.
SUMMARY OF THE DISCLOSURE
[0005] Disclosed herein is a method of measuring two or more fluid
phases of in a downhole well bore that comprises measuring a flow
of each of the two or more phases at respective offtake points at
which the two or more phases are unmixed within the well bore.
[0006] In certain implementations, the well bore is inclined at 20
degrees or less to a horizontal axis. Each of the two or more
phases can flow at a rate to achieve low Reynolds numbers in a
laminar flow regime.
[0007] In certain implementation, the two or more phases mix
downstream from the offtake points.
[0008] In certain embodiments, the method further includes
immersing level sensors within the two more fluid phases.
[0009] In certain embodiments, the method further includes
measuring the pressure of the two or more phases at the respective
offtake points.
[0010] In certain embodiments, the method further includes coupling
a variable valve having an opening to each offtake point used to
measure each of the separate two or more phases. The opening of
variable valves can be controlled to maintain separation of the two
or more flowing phases during an entire production period.
[0011] In certain embodiments, the method further includes
determining a flow rate of the two or more phases based on pressure
at the offtake points according to the equation:
Q i = C V i .DELTA. p .rho. i ##EQU00001##
in which Qi is the flow rate of the ith phase, C.sub.Vi is a
coefficient related to the properties of the variable valve of the
ith variable valve, .DELTA.p is a pressure differential measured at
the ith offtake point, .rho..sub.w is the density of the ith phase,
and in which the two or more phases number 1 to i.
[0012] Also disclosed herein is a system for of measuring two or
more fluid phases of in a downhole well bore that comprises a
plurality of sensors, one of the plurality of sensors measuring a
flow in each one of the two or more phases at respective offtake
points at which the two or more phases are unmixed within the well
bore. In certain implementations, the plurality of sensors
comprises plural pressure sensors.
[0013] In certain embodiments, the system further includes a
plurality of level sensors, one of the plurality of level sensors
being immersed in each one of the respect two or more phases.
[0014] In certain embodiments, the system further includes a
plurality of valves for controlling inflow so as to maintain an
interface level between the at least two phases.
[0015] In certain implementations, the well bore is inclined at 20
degrees or less to a horizontal axis. Each of the two or more
phases can flow at a rate to achieve low Reynolds numbers in a
laminar flow regime.
[0016] In certain implementations, the two or more phases mix
downstream from the offtake points.
[0017] These and other aspects, features, and advantages can be
appreciated from the following description of certain embodiments
of the disclosure and the accompanying drawing figures and
claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0018] FIG. 1 is a longitudinal cross-section of an embodiment of a
system for metering multiphase flow according to the present
disclosure.
[0019] FIG. 2 is a latitudinal cross-section of the embodiment of
the system for metering multiphase flow taken along axis A-A' shown
in FIG. 1.
[0020] FIG. 3 is a schematic diagram fluid flow path from the
annulus into the tubing. in embodiments of the disclosed system for
metering multiphase flow.
[0021] FIGS. 4A to 4D illustrate flow regimes at different flow
rates for stratified two-phase flow in a horizontal
compartment.
[0022] FIG. 5 is a flow chart of an embodiment of a method of
controlling valve of the system for metering multiphase flow to
maintain an interface level according to the present
disclosure.
[0023] FIG. 6 is a perspective view of an exemplary inflow port
control valve that can be used in the disclosed systems for
metering multiphase flow.
[0024] FIG. 7 is a perspective view of an exemplary capacitive
level sensor that can be used in the disclosed systems for metering
multiphase flow.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS OF THE DISCLOSURE
[0025] Systems and methods for measuring two-phase flow (i.e., flow
including two components such as water and oil) in downhole well
compartments are disclosed herein. The two-phase flow arrives in an
unmixed state or is separated into its components and stratified
(into top and bottom portions) inside a horizontal well
compartment. In either case, the phases are maintained in an
unmixed state within the horizontal well compartment. The well
compartment apparatus includes tubing having flow ports arranged to
permit flow from the annulus surrounding the tubing. One set of
ports is permeated by one of the two phases, while another set of
ports is permeated by the other phase, allowing the flow of each
phase to be measured separately. The level of the interface between
the stratified phases is maintained using level sensors and
adjustable valves that control the flow from the annulus into to
the production tubing.
[0026] The flows are stratified to facilitate flow measurement
because determining flow rates in a mixed, multiphase flow is
considerably more complex. In embodiments of the system,
differential pressure gauges such as Venturi devices can be used to
measure the two single-phase flows; one differential pressure gauge
can be positioned in each layer in the stratified flow. As each
phase flows through an inflow orifice, the pressure drop across
that orifice is measured. The phase fraction of either component
can then be calculated by accumulating the phase volume flow over a
period and dividing it by the total fluid volume.
[0027] Experiments and mathematical modelling including computation
fluid dynamic analyses, show that under most prevalent conditions,
flow tends to stratify in the horizontal well compartment without
needing additional stratification elements or techniques. Table 1
below includes typical fluid properties used in computation fluid
dynamics analyses. Table 2 below details several cases in which
different flow parameters for oil and water were tested.
TABLE-US-00001 TABLE I (fluid properties) Surface Viscosity Density
Concentric Pipe tension (water/oil) (water/oil) Diameter internal
length (N/m) (cP) (kg/m3) (m) diameter (m) (m) 0.01 1/0.8 1000/800
0.15 0.11 2.5
TABLE-US-00002 TABLE II (Tests with varying flow parameters)
Annulus Inlet velocities Compartment Flow Reynolds Froude
(water/oil) (m/s) rate (BPD) number number Case 1 0.08/0.02 500
7,000 0.06 Case 2 0.16/0.04 1,000 14,000 0.12 Case 3 1.5/0.25 8,500
130,000 0.7 Case 4 2.4/0.4 13,500 210,000 1.2
[0028] In the computation fluid dynamics analyses, in cases 1 and
2, the velocities were set at typical inlet and compartment flow
rates. In cases 3 and 4 the inlet and compartment flow rate
parameters were set at very high levels, representing "worst case"
scenarios. The analyses calculated the Froude number, which is a
dimensionless parameter that is defined as the ratio of the fluid
inertia to the external field, typically gravity. Generally, for a
multiphase fluid, a Froude number below 1.0 implies that gravity
dominates fluid inertia, and that the fluid will tend to separate
into its components and stratify at low to medium velocities.
Froude numbers above but near 1.0 are representative of a "wavy
stratified" flow regime. The results of the analyses demonstrate
that at the typical inlet and compartmental flow velocities, the
Froude number is considerably below 1 and that the fluid can be
expected to stratify up to 8,500 BPD (barrels per day). At a flow
rate of 10,000 BPD, which represents a top expected flow rate, the
wavy stratified regime begins. In sum, the analyses show that
stratification can be expected to occur without large waves through
the entire range of expected flow rates. The systems and methods
for metering multiphase flow disclosed herein are based upon these
robust findings.
[0029] FIGS. 4A through 4D illustrate multiphase flow through a
horizontal compartment at different flow rates. FIG. 4A and FIG. 4B
illustrate flow at 500 BPD and 1000 BPD, respectively. As
illustrated, the phases of oil and water are stratified, and the
flow of the phases is not wavy. As shown in FIG. 4C, at a flow rate
of 8500 BPD, while the flow remains stratified, the interface
between the oil and water is uneven, indicating the start of wavy
flow. At 13,500, shown in FIG. 4D, there are significant waves and
turbulence in the water phase. As noted, flow rates in the
horizontal compartment are expected to remain within the ranges
depicted in FIGS. 4A-4C, and the unstable flow shown in FIG. 4D is
highly unlikely.
[0030] FIG. 1 is a longitudinal cross-section of an embodiment of a
system for metering multiphase flow according to the present
disclosure. FIG. 1 shows a horizontal well compartment 100 situated
within a geological formation. The compartment includes tubing 102
that runs through the longitudinal extent of the compartment. The
tubing 102 is surrounded by an annulus 104 positioned between the
tubing and the geological formation through which the horizontal
well is constructed. Packers 110, 112 are positioned at the
respective left and right ends of the compartment 100 in the
annulus 104 to isolate the compartment from other sections of the
infrastructure. Inflow ports, e.g., 122, 124 are positioned across
the tubing. In the embodiment depicted, the tubing 102 includes
four inflow ports (of which two are shown in the cross-sectional
view) but in other embodiments, it is possible to use fewer or a
larger number of input ports.
[0031] The inflow ports, e.g., 122, 124 can be spaced in an
equidistant manner around the circumference of the tubing so that
they are 90 apart from each other over a 360 span. This arrangement
ensures that at least one inflow port is within one of the two
stratified phases at all times. FIG. 2A is a latitudinal
cross-sectional view through axis A-A' shown in FIG. 1. In this
view, all four inflow ports 122, 124, 126, 128 are shown and their
relative spacing is more clearly depicted. Each inflow port 122,
124, 126, 128, includes both an orifice and a control valve. In
this arrangement the inflow ports are positioned in approximately
up, down, left and right orientations. FIG. 2B shows an alternative
configuration in which the inflow ports 123, 125, 127, 129 are
offset by 45 degrees with respect to the orientations shown in FIG.
2B. This arrangement represents a worst-case scenario in that the
inflow ports are positioned more closely to the interface between
oil and water phases. If significant waves form, one or more inflow
ports can be submerged in the other phase.
[0032] Each inflow port 122, 124, 126, 128 includes an orifice and
a control valve that is adapted to allow or close off flow through
the inflow ports based on a control signal received from an
electronic control unit. An example control valve 402 that can be
used in the present context, shown in FIG. 6, is the 422 Series
Shear Seal.RTM. solenoid valve manufactured by Barksdale Inc. of
Los Angeles, Calif. The control valve is capable of opening and
closing (on/off position) repeatedly. The 422. Series has a minimum
flow diameter of 5.6 mm, is rated for a working pressure up to 3000
psi and can handle tens of thousands of on-off cycles. Each inflow
port also acts as a choke in that there is a measurable pressure
drop across the valve from the exterior to the interior of the
tubing 102.
[0033] Returning to FIG. 1, a differential pressure gauge 132 has a
first part positioned in the interior of tubing 102 and another
part positioned in the annulus 104 to measure the pressure drop
across the inflow ports in one of the phases. A second differential
pressure gauge (not shown in FIG. 1) measures the same pressure
drop within the second phase. The pressure drop is used to
calculate volumetric flow using Bernoulli's principle. A plurality
of level sensors 142, 144, 146 are affixed to the external surface
of the tubing. The level sensors are adapted to measure the fluid
interface level in the annulus. Using a plurality of level sensors
positioned around the circumference of the tubing ensures that the
interface level between the separate phases present in the annulus
can be determined. An example embodiment of a level sensor 412,
shown in FIG. 7, is a multiple capacitance sensor manufactured by
Omega Engineering, Inc. of Norwalk, Conn.
[0034] The control valves, differential pressure gauge and level
sensors are provided with electrical power via electrical line 150
that extends through the compartment. Returning to FIGS. 2A and 2B,
exemplary arrangements of the level sensors are shown. In the
arrangement of FIG. 2A, four level sensors 142, 144, 146 and 148
are positioned adjacent to respective inflow valves 122, 124, 126,
128. Similarly, in the arrangement of FIG. 2B, in which the inflow
valves are rotated 45.degree. with respect to the vertical and
horizontal axes, level sensors 143, 145, 147 and 149 are positioned
adjacent inflow valves 122, 124, 126, 128. Each of level sensors
and their respective positions can be uniquely identified by the
electronic control unit. In the example shown in FIG. 2B, the
interface level is determined to be between the height of level
sensors 145, which is higher than level sensor 147 but still
submerged in water, and level sensor 149, which is lower than level
sensor 143 but still submerged in oil.
[0035] FIG. 3 is a schematic diagram of a fluid flow path from the
annulus 104 into the tubing 12. Oil and water in the annulus
flowing in path 202 stratify, with oil being directed through a top
flow segment 204 and water through a bottom flow segment 206. Oil
in flow segment 204 flows through an inflow port (and control
valve) 122, located at first position into the tubing 102. Water in
flow segment 206 flows through a second inflow port (and control
valve) 124, located at a lower position that the first control
valve into the tubing as well. The first control valve 122 thereby
controls the inflow of oil (alone) into the tubing and the second
control valve 124 only controls the inflow of water, and aids in
maintaining stratification of the phases. A first pressure gauge
132 measures the pressure drop across the first inflow port 122
(between the annulus and the interior of the tubing) and a second
pressure gauge 134 measures the pressure drop across the second
inflow port 124 (also between the annulus and the interior of the
tubing).
[0036] As shown in FIG. 1, flows of oil and water are stratified,
with oil flowing in a lop layer and water flowing in a bottom layer
and an interface where the layers of the two phases meet. In some
cases, the two phases flow into the compartment separately in an
unmixed state. An electronic control unit (not shown) coupled to
the control valves implements a method for maintaining the height,
H(t), of the interface between the oil and water phases as part of
the method of metering multiphase flow according to the present
disclosure. The electronic control unit (not shown in FIG. 1) can a
processor that is operative to execute accessible stored program
instructions, or it can be a programmable logic unit or
application-specific circuit that automatically responds to
received signals to implement the control method. In some
embodiments, the control unit is positioned in a surface facility
and sends and receives electrical signals to the components of the
apparatus over conductive line 150. The control algorithm defines a
top threshold, H.sub.1, which is the highest level at which the
interface can be allowed to rise, and a low threshold, H.sub.2,
which is the lowest level at which the interface can be allowed to
fall. The control algorithm operates to maintain the interface
level between H.sub.1 and H.sub.2.
[0037] FIG. 5 is a flow diagram of an embodiment of a method for
metering multiphase flow according to the present disclosure. In
step 500, the method begins. In step 502, the positions of the
level sensors are identified; in the following step 504, from the
identification of the level sensors, the control unit identifies
the inflow ports (associated with the level sensors) that are
positioned at the top and bottom of the tubing, which are
designated as the main inflow ports, and the other ports ("back-up"
inflow ports) that are positioned nearer to the fluid interface (as
per the arrangement of FIG. 2A). In step 506, the control unit sets
the valve conditions for initial metering by shutting the control
valves of the back-up inflow ports and leaving the control valves,
V.sub.t and V.sub.b of the main inflow ports open. After
initialization, the control valves are operated to maintain the
interface level H(t) between minimum and maximum thresholds.
[0038] In step 512, starting from the condition in which both main
valves are open, readings are obtained from the level sensors to
determine an initial interface level H(t). In step 514, new level
sensor readings are obtained, and from the new readings, the
direction in which H(t) has changed (if at all) is determined. If,
in step 514, it is determined that H(t) is moving up, in step 516,
the top inflow valve V.sub.t is closed. Following this flow path,
in step 518, it is determined whether H(t) has reached the bottom
threshold height H.sub.2. When H(t) reaches H.sub.2, valve V.sub.t
is opened in step 520. Thereafter, the process cycles back to step
512. Returning to step 514, if is determined that H(t) is moving
down, in step 522, the bottom inflow valve V.sub.b is closed. In
this flow path, in step 524, it is determined whether H(t) has
reached the top threshold height H1. When H(t) reaches H1, valve
V.sub.b is opened in step 526. Thereafter, the process cycled back
to step 512. This flow provides for continuous monitoring and
control over the fluid interface level between the phases in the
horizontal compartment.
[0039] With the ability to have single phase flow through each
valve, the oil flow rates through the orifice is calculated as
follows:
Q.sub.o=Q.sub.V.sub.T=.intg..sub.tQ(t).sub.V.sub.T (1)
in which t represents time, Q.sub.o represents the oil flow rate,
and Q.sub.V.sub.T represents the flow rate through the top main
inflow port as a function of time. These two values are equal since
oil always flows from the top port. The Q.sub.V.sub.T term can be
calculated as:
Q ( t ) V T = 0 if V T is closed ( 2 ) C V T .DELTA. p .rho. o if V
T is open ( 3 ) ##EQU00002##
in which C.sub.V.sub.T represents the top valve coefficient,
.DELTA.p represents the measured pressure drop between the annulus
and the tubing, and P.sub.O represents the oil density.
[0040] Similarly, the water flow rate through the orifice is
determined as:
Q.sub.w=Q.sub.V.sub.B=.intg..sub.tQ(t).sub.V.sub.B (4)
in which Q.sub.w is the water flow rate and Q.sub.V.sub.B is the
rate of water flow through the bottom main inflow port. These two
values are equal since water always flows from the bottom port.
The
Q ( t ) V B can be calulated as : ##EQU00003## Q ( t ) V B = 0 if V
B is closed ( 5 ) { C V B .DELTA. p .rho. w if V B is open ( 6 )
##EQU00003.2##
in which C.sub.V.sub.B is the bottom valve coefficient, .DELTA.p is
the pressure drop between the annulus and the tubing, and
.rho..sub.w is the water density.
[0041] The two-phase flow measurement can be fully determined by
defining the total flow, Q.sub.t, and water cut, WC, as:
Q t = Q w + Q o ( 7 ) WC = Q w Q t ( 8 ) ##EQU00004##
[0042] According to the disclosed method, the rate of oil flow
(Q.sub.VT) and the rate of water flow (Q.sub.VB) can be separately
determined from the known characteristics of the valves (C.sub.VT,
C.sub.VB), the measured pressure drop between the annulus and the
inside of the tubing, and the densities of oil and water.
Similarly, the total flow and water cut are easily determined from
the oil flow and water flow. Complex calculations that are required
for mixed flows are not necessary and determinations of flow
characteristics is straightforward.
[0043] The system and methods disclosed above can be used for
separating fluids have more than two phases. For example, three or
more fluids can be separated if there is an adjustable orifice for
each distinct phase.
[0044] It is to be understood that any structural and functional
details disclosed herein are not to be interpreted as limiting the
systems and methods, but rather are provided as a representative
embodiment and/or arrangement for teaching one skilled in the art
one or more ways to implement the methods.
[0045] It is to be further understood that like numerals in the
drawings represent like elements through the several figures, and
that not all components and/or steps described and illustrated with
reference to the figures are required for all embodiments or
arrangements.
[0046] The terminology used herein is for the purpose of describing
particular embodiments only and is not intended to be limiting of
the disclosure or the invention described herein. As used herein,
the singular forms "a", "an" and "the" are intended to include the
plural forms as well, unless the context clearly indicates
otherwise. It will be further understood that the terms "comprises"
and/or "comprising", when used in this specification, specify the
presence of stated features, integers, steps, operations, elements,
and/or components, but do not preclude the presence or addition of
one or more other features, integers, steps, operations, elements,
components, and/or groups thereof.
[0047] Terms of orientation are used herein merely for purposes of
convention and referencing and are not to be construed as limiting.
However, it is recognized these terms could be used with reference
to a viewer. Accordingly, no limitations are implied or to be
inferred.
[0048] Also, the phraseology and terminology used herein is for the
purpose of description and should not be regarded as limiting. The
use of "including," "comprising," or "having," "containing,"
"involving," and variations thereof herein, is meant to encompass
the items listed thereafter and equivalents thereof as well as
additional items.
[0049] While the disclosure has been described with reference to
exemplary embodiments, it will be understood by those skilled in
the art that various changes may be made and equivalents may be
substituted for elements thereof without departing from the scope
of the disclosure. In addition, many modifications will be
appreciated by those skilled in the art to adapt a particular
instrument, situation or material to the teachings of the
disclosure without departing from the essential scope thereof.
Therefore, it is intended that the invention not be limited to the
particular embodiment disclosed as the best mode contemplated for
carrying out this disclosure, but that the invention will include
all embodiments falling within the scope of the disclosure as
understood by one of ordinary skill in the art.
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