U.S. patent application number 15/516843 was filed with the patent office on 2017-08-31 for debris control systems, apparatus, and methods.
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 Kenneth Lee Borgen, Andrew Michael Smith, Clifford Lynn Talley.
Application Number | 20170247981 15/516843 |
Document ID | / |
Family ID | 56127112 |
Filed Date | 2017-08-31 |
United States Patent
Application |
20170247981 |
Kind Code |
A1 |
Smith; Andrew Michael ; et
al. |
August 31, 2017 |
DEBRIS CONTROL SYSTEMS, APPARATUS, AND METHODS
Abstract
A debris control system comprises a first ported sub and a
second ported sub attached to a casing and disposed in a wellbore,
such that the first ported sub is disposed at a depth that is
deeper than the depth at which the second ported sub is disposed.
The first ported sub is to move debris from the wellbore when it is
actuated and a first fluid is pumped through it. The second ported
sub is to enable conducting a diagnostic fracture injection test
(DFIT) when a second fluid is pumped through it. Additional
apparatus, methods, and systems are disclosed.
Inventors: |
Smith; Andrew Michael;
(Odessa, TX) ; Borgen; Kenneth Lee; (Midland,
TX) ; Talley; Clifford Lynn; (Midland, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
56127112 |
Appl. No.: |
15/516843 |
Filed: |
December 16, 2014 |
PCT Filed: |
December 16, 2014 |
PCT NO: |
PCT/US2014/070544 |
371 Date: |
April 4, 2017 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 49/008 20130101; E21B 33/12 20130101; E21B 2200/06 20200501;
E21B 37/10 20130101; E21B 34/063 20130101; E21B 34/10 20130101;
E21B 37/00 20130101 |
International
Class: |
E21B 37/00 20060101
E21B037/00; E21B 34/10 20060101 E21B034/10; E21B 37/10 20060101
E21B037/10; E21B 43/26 20060101 E21B043/26; E21B 34/06 20060101
E21B034/06; E21B 33/12 20060101 E21B033/12; E21B 49/00 20060101
E21B049/00 |
Claims
1. A method, comprising: pumping a first fluid through a first
ported sub to remove debris from a wellbore in which a casing
attached to the first ported sub is disposed, to provide a cleaned
wellbore; sealing the wellbore at a first depth; and pumping a
second fluid through a second ported sub to conduct a diagnostic
fracture injection test in the cleaned wellbore, wherein the first
depth is deeper than a second depth at which the second ported sub
is attached to the casing.
2. The method of claim 1, further comprising: running the casing
into the wellbore prior to pumping the first fluid.
3. The method of claim 1, further comprising: enabling fluid
communication between the wellbore and a formation via ports on the
first ported sub prior to pumping the first fluid.
4. The method of claim 1, further comprising: enabling fluid
communication between the wellbore and a formation via ports on the
second ported sub prior to pumping the second fluid.
5. The method of claim 1, wherein the first fluid comprises a
solvent cleanout fluid.
6. The method of claim 1, wherein the second fluid comprises
formation compatible fluid.
7. A system, comprising: a first ported sub attached to a casing
and disposed at a first depth in a wellbore, wherein the first
ported sub is to pass debris from the wellbore when the first
ported sub is actuated and a first fluid is pumped through the
first ported sub; and a second ported sub disposed at a second
depth in the wellbore, wherein the first depth is deeper than the
second depth, the second ported sub to enable conducting a
diagnostic fracture injection test when a second fluid is pumped
through the second ported sub.
8. The system of claim 7, further comprising: a first landing
collar disposed at a third depth that is deeper than the first
depth.
9. The system of claim 8, further comprising: a wiper dart to pass
through the wellbore to control the amount of debris in the
wellbore.
10. The system of claim 9, further comprising: a second landing
collar disposed at a fourth depth that is between the first and
second depths, wherein the second landing collar has an inner
diameter greater than an inner diameter of the first landing
collar, such that the wiper dart passes through inner diameter of
the second landing collar.
11. The system of claim 10, further comprising: a wiper plug to
land in the second landing collar so as to create a seal in the
wellbore.
12. The system of claim 7, wherein at least one of the first ported
sub or the second ported sub comprises a hydraulically actuated
sliding sleeve.
13. A method, comprising: installing a plurality of tools on a
casing, the plurality of tools comprising a first ported sub and a
second ported sub; running the casing into a wellbore; performing a
completion operation; and opening the first ported sub to pass
debris from the wellbore, prior to opening the second ported sub to
conduct a diagnostic fracture injection test.
14. The method of claim 13, wherein opening the first ported sub
comprises: applying hydraulic pressure to the first ported sub, so
as to shear one or more shear fasteners.
15. The method of claim 13, further comprising: pumping a solvent
into the wellbore to pass debris from the wellbore through the
first ported sub.
16. The method of claim 13, further comprising: opening the second
ported sub after the first ported sub is plugged.
17. The method of claim 13, further comprising: sealing the
wellbore at a first depth, wherein the first ported sub is located
at a second depth that is equal to, or deeper than, the first
depth.
18. The method of claim 17, wherein sealing the wellbore comprises:
landing a wiper plug at a landing collar disposed at the casing
between the first ported sub and the second ported sub, wherein the
plurality of tools comprises the landing collar.
19. The method of claim 17, further comprising: opening the second
ported sub after sealing the wellbore, wherein the second ported
sub is disposed at a third depth, wherein the first depth is deeper
than the third depth.
20. The method of claim 17, further comprising: performing a
diagnostic fracture injection test or a hydraulic fracturing
treatment using the second ported sub.
Description
BACKGROUND
[0001] Diagnostic fracture injection tests (DFITs) are commonly
used to obtain formation properties and determine fracture
parameters associated with a wellbore. Typically, fluid is pumped
horizontally through the toe or vertically through perforations of
the wellbore. The pressure at the wellhead is then monitored for an
extended period of time. Cementing residue, pipe dope, or other
debris can obstruct the flow path from the wellbore to the
formation, making pressure data uninterpretable, unreliable, or
otherwise causing the DFIT to fail. The debris in the wellbore may
further interfere with hydraulic fracturing treatments. The
accumulated debris can be difficult, if not impossible, to remove
without costly intervention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0002] The present disclosure may be better understood, and its
numerous features and advantages made apparent to those of ordinary
skill in the art by referencing the accompanying drawings. The use
of the same reference symbols in different drawings indicates
similar or identical items.
[0003] FIG. 1 depicts an example debris control system, in
accordance with some embodiments.
[0004] FIG. 2 depicts another example of the debris control system
of FIG. 1, in accordance with some embodiments.
[0005] FIG. 3 depicts yet another example of the debris control
system of FIG. 1, in accordance with some embodiments.
[0006] FIG. 4 depicts yet another example of the debris control
system of FIG. 1, in accordance with some embodiments.
[0007] FIG. 5 is a flow diagram of an example method of debris
control, in accordance with some embodiments.
[0008] FIG. 6 depicts an example completion system, in accordance
with some embodiments.
DETAILED DESCRIPTION
[0009] FIGS. 1-5 illustrate example methods, apparatus, and systems
for debris control during well construction, and other operations,
using a first ported sub and a second ported sub attached to a
casing, so that when the casing is inserted into a wellbore, the
first ported sub is positioned deeper in the wellbore than the
second ported sub. The first ported sub is actuated to provide
fluid communication between the wellbore and a formation, such that
a fluid can be pumped through the first ported sub to move debris
out of the wellbore and into the formation. The wellbore is then
sealed and the second ported sub is actuated to allow fluid
communication between the wellbore and the formation, such that a
diagnostic fracture injection test (DFIT) or a hydraulic fracturing
treatment may be performed without interference from the debris
that has passed through the first ported sub.
[0010] FIG. 1 depicts an example debris control system 100, in
accordance with some embodiments. The debris control system 100
generally comprises a first ported sub 102 and a second ported sub
104 attached to a casing 106 for use in a wellbore 108. In at least
one embodiment, the debris control system 100 further comprises a
first landing collar 110 and a second landing collar 112 attached
to the casing 106. In some embodiments, a guide shoe 114 is
attached to an end of the casing 106 to guide the casing 106 into
the wellbore 108. In some embodiments, a float collar 116 is
attached to the casing 106. In the illustrated embodiment, the
debris control system 100 is installed on the casing 106 so that
when the casing 106 is run into the wellbore 108, the guide shoe
114 is deeper than the float collar 116, which is, in turn, deeper
than the first landing collar 110. The landing collar 110 is deeper
than the first ported sub 102, which is, in turn, deeper than the
second landing collar 112. The second landing collar 112 is, in
turn, deeper than the second ported sub 104.
[0011] For the purposes of this disclosure, "depth" is relative to
the casing 106 once inserted into the wellbore 108. That is, an
element A having a "deeper" depth than element B indicates that
element A has a position on the casing 106 that would be further
into the wellbore 108 than element B, once the casing 106 is
inserted into the wellbore 108.
[0012] In the illustrated embodiment, the second landing collar 112
comprises an inner diameter that is greater than an inner diameter
of the first landing collar 110, such that a wiper dart 120
inserted into the casing 106 passes through the inner diameter of
the second landing collar 112, and lands in the first landing
collar 110, substantially sealing the casing 106 at the first
landing collar 110 against the incursion of fluid.
[0013] In at least one embodiment, at least one of the first ported
sub 102 and the second ported sub 104 comprises a sliding sleeve.
Further, in some embodiments, at least one of the first ported sub
102 and the second ported sub 104 comprises a hydraulically
activated sliding sleeve. In some embodiments, at least one of the
first ported sub 102 and the second ported sub 104 can be actuated
to facilitate fluid communication between the wellbore 108 and a
formation 118. In some embodiments, at least one of the first
ported sub 102 and the second ported sub 104 establishes the fluid
communication between the wellbore 108 and the formation 118
independently, without intervention of a perforating gun or some
other ancillary mechanism. In some embodiments, at least one of the
first ported sub 102 and the second ported sub 104 only requires
the imposition of absolute casing pressure (applied pressure and
hydrostatic pressure) to be actuated.
[0014] In some embodiments, at least one of the first ported sub
102 and the second ported sub 104 comprises a variable-sized inner
mandrel to create a piston area and atmospheric chamber inside a
ported housing. The piston area and atmospheric chamber generate a
hydraulic force on the inner sleeve as the inner diameter of the
ported sub (102, 104) is exposed to pressure (both hydrostatic and
applied).
[0015] The inner mandrel is fastened in place by shear fasteners,
for example, shear pins, shear screws, or the like. The number of
shear fasteners can be manipulated to achieve different pressure
requirements for actuation. When the total internal pressure
generates the predetermined hydraulic force, the shear fasteners
are sheared and the inner mandrel is allowed to move, exposing the
ports of the ported sub (102, 104) and facilitating fluid
communication between the wellbore 108 and the formation 118. In
the illustrated embodiment, both the first ported sub 102 and the
second ported sub 104 are in a closed position, such that the ports
of the ported subs 102, 104 do not facilitate fluid communication
between the wellbore 108 and the formation 118.
[0016] FIG. 2 depicts another example of the debris control system
100 of FIG. 1, in accordance with some embodiments. In the
illustrated embodiment, the wiper dart 120 has passed through the
wellbore 108 and the inner diameter of the second landing collar
112 to control the amount of debris in the wellbore 108, and landed
in the first landing collar 110 to seal the wellbore 108. Further,
in the illustrated embodiment, the first ported sub 102 has been
actuated such that it is in an open position to facilitate fluid
communication between the wellbore 108 and the formation 118. In at
least one embodiment, hydraulic pressure is used to open the first
ported sub 102.
[0017] In some embodiments, a fluid is pumped through the wellbore
108 to move debris from the wellbore 108 to the formation 118, via
the first ported sub 102. The debris may comprise, for example,
cementing residue, pipe dope, solids, or the like. In at least one
embodiment, the fluid comprises primarily water. In at least one
embodiment, the fluid comprises a solvent cleaning fluid, for
example, a solvent acid, acids, organic acids, aromatic solvents,
paraffinic solvents, soaps, detergents, a combination of these, or
the like. In some embodiments, the fluid is chosen to treat
specific anticipated pipe debris.
[0018] In the illustrated embodiment, the second ported sub 104 has
not been actuated and remains in a closed position, such that the
second ported sub 104 does not facilitate fluid communication
between the wellbore 108 and the formation 118. That is, the
actuation of the first ported sub 102 does not result in actuation
of the second ported sub 104. For example, in at least one
embodiment, the second ported sub 104 is actuated by application of
a greater pressure than is required to actuate the first ported sub
102. In at least one embodiment, both the first ported sub 102 and
the second ported sub 104 comprise hydraulically actuated sliding
sleeves with shear fasteners, and the shear fasteners on the second
ported sub 104 comprise greater shear strength than those on the
first ported sub 102.
[0019] The illustrated embodiment further depicts a wiper plug 202
passing through the casing 106 of the wellbore 108. The wiper plug
202 is dimensioned to land and latch into the second landing collar
112 to seal the wellbore 108 at a lesser depth than the depth of
the first ported sub 102. In at least one embodiment, the debris
control system 100 does not include the second landing collar 112,
and instead the wiper plug 202 is dimensioned to land and latch
into the first ported sub 102 to seal the wellbore 108. In some
embodiments, the debris control system 100 does not use the wiper
plug 202. In at least one embodiment, the first ported sub 102 is
plugged, for example, by debris, sealing the wellbore 108 from the
formation 118 where the debris has been disposed.
[0020] FIG. 3 depicts yet another example of the debris control
system 100 of FIG. 1, in accordance with some embodiments. In the
illustrated embodiment, the wiper plug 202 has landed and latched
into the second landing collar 112, to seal the wellbore 108 from
the formation 118. In at least one embodiment, the sealed wellbore
creates a "disposal zone" of sorts, such that debris is trapped
between the wiper plug 202, the wiper dart 120 and the formation
118. In at least one embodiment, the wellbore 108 is sealed from
the formation 118 by debris plugging the first ported sub 102.
[0021] In the illustrated embodiment, the second ported sub 104 has
been actuated, such that the second ported sub 104 facilitates
fluid communication between the wellbore 108 and the formation 118.
In at least one embodiment, hydraulic pressure is used to open the
second ported sub 104. The second ported sub 104 may be used for at
least one of: a DFIT or a hydraulic fracturing treatment without
interference from the debris that has passed through the first
ported sub 102, or is otherwise trapped below the wiper plug
202.
[0022] FIG. 4 depicts yet another example of the debris control
system 100 of FIG. 1, in accordance with some embodiments. In the
illustrated embodiment, the debris control system 100 does not
include the second landing collar 112 of the wiper plug 202.
Instead, the first ported sub 102 is actuated in accordance with
FIG. 2 to facilitate fluid communication between the wellbore 108
and the formation 118 to pass debris to the formation 118. Debris
eventually plugs the first ported sub 102 to seal the wellbore 108
from the debris that has passed through the first ported sub 102 to
the formation 118. The second ported sub 104 is then actuated to
facilitate fluid communication between the formation 118 and the
wellbore. In the illustrated embodiment, the second ported sub 104
is in the open position to facilitate a DFIT or a hydraulic
fracturing treatment without interference from the debris that was
passed to the formation 118 via the first ported sub 102.
[0023] FIG. 5 is a flow diagram of an example method 500 of debris
control, in accordance with some embodiments. For the purposes of
clarity, the method 500 is described with reference to the debris
control system 100 of FIGS. 1-4. At block 502 a plurality of tools
comprising components of the debris control system 100 are
installed on the casing 106. In at least one embodiment, the debris
control system 100 is installed at the toe of the casing 106. In at
least one embodiment, the first ported sub 102 is disposed at a
first depth that is deeper than a depth at which the second ported
sub 104 is disposed. In at least one embodiment, the first landing
collar 110 is disposed at a depth that is deeper than a depth at
which the first ported sub 102 is disposed. In at least one
embodiment, the second landing collar 112 is disposed between the
first ported sub 102 and the second ported sub 104.
[0024] At block 504, one or more well completion operations are
performed. The casing 106 is run into the wellbore 108. In some
embodiments, the completion operations comprise pumping cement down
the casing 106 to the guide shoe 114, where it continues to flow up
the annulus between the casing 106 and the wellbore 108, isolating
the wellbore from the formation 118. In at least one embodiment,
the wiper dart 120 is landed in the first landing collar 110 to
prevent u-tubing of cement (e.g., the return of cement into the
wellbore) during the completion operations. The second landing
collar 112 has an inner diameter that is greater than an inner
diameter of the first landing collar 110, such that the wiper dart
120 passes through the second landing collar 112 to seat in the
first landing collar 110 and seal the wellbore 108.
[0025] At block 506, the first ported sub 102 is actuated, enabling
fluid communication between the wellbore 108 and the formation 118
via ports on the first ported sub 102. In at least one embodiment,
hydraulic pressure is used to actuate the first ported sub 102. In
at least one embodiment, pressure is applied to shear one or more
shear fasteners of the first ported sub 102 to actuate the first
ported sub 102. The second ported sub 104 has not been actuated and
remains in a closed position at this point, such that the second
ported sub 104 does not facilitate fluid communication between the
wellbore 108 and the formation 118. That is, the actuation of the
first ported sub 102 does not result in actuation of the second
ported sub 104. For example, in at least one embodiment, the second
ported sub 104 is actuated by application of a greater pressure
than is required to actuate the first ported sub 102. In at least
one embodiment, both the first ported sub 102 and the second ported
sub 104 comprise hydraulically actuated sliding sleeves with shear
fasteners, and the fasteners on the second ported sub 104 comprise
greater shear strength than the fasteners on the first ported sub
102.
[0026] At block 508, fluid is pumped through the wellbore 108 to
pass debris from the wellbore 108 and provide a cleaned wellbore
108. In some embodiments, the fluid passes the debris from the
wellbore 108 to the formation 118 via the first ported sub 102. The
debris may comprise, for example, cementing residue, pipe dope,
solids, or the like. In at least one embodiment, the fluid
comprises primarily water. In some embodiments, the fluid comprises
a solvent. In at least one embodiment, the fluid comprises a
solvent cleaning fluid. In some embodiments, the fluid is chosen to
treat specific anticipated pipe debris.
[0027] At block 510, it is determined whether the first ported sub
102 is plugged by debris. For example, in at least one embodiment,
this determination is made by increasing excessive pressure, based
on an inability to maintain injection rate, or a combination of
these.
[0028] If, at block 510, it is determined that the first ported sub
102 is not plugged by debris, the method proceeds to block 512,
whereby a wiper plug 202 is landed and latched into the second
landing collar 112. The wiper plug 202 seals the wellbore 108
between the first ported sub 102 and the second ported sub 104, so
as to separate the cleaned wellbore from the debris that has been
passed through the first ported sub 102 to the formation 118. In at
least one embodiment, the wiper plug 202 is landed and latched into
the first ported sub 102, such that the wellbore 106 is sealed by
the wiper plug 202 at the first ported sub 102.
[0029] If, at block 510, it is determined that the first ported sub
102 is plugged by debris, then the wellbore 108 is sealed (by the
plugged first ported sub 102) from the debris that has passed
through the first ported sub 102 to the formation 118. After the
wellbore 108 is sealed by debris or by the wiper plug 202, the
method 500 proceeds to block 514, whereby the second ported sub 104
is actuated, enabling fluid communication between the wellbore 108
and the formation 118 via ports on the second ported sub 104. In at
least one embodiment, hydraulic pressure is used to actuate the
second ported sub 104. In at least one embodiment, pressure is
applied to shear one or more shear fasteners of the second ported
sub 104 to actuate the second ported sub 104.
[0030] At block 516, a diagnostic fracture injection test (DFIT) or
a hydraulic fracturing treatment is performed using the second
ported sub 104. In at least one embodiment, a second fluid is
pumped through the second ported sub 104. For example, in at least
one embodiment, the fluid comprises non-damaging treated water, a
compatible field brine, oil, gas, foam, a combination of these, or
the like. In some embodiments, data is collected, and a DFIT
analysis is performed on the data. In at least one embodiment, the
DFIT comprises a small volume, cost-effective, short duration and
low-rate injection test followed by an extended shut-in period. In
at least one embodiment, the DFIT comprises breaking down the
formation 118 and estimating fracture pressure, closure pressure,
pore pressure, and permeability. In some embodiments, the DFIT is
performed in an effort to optimize a hydraulic fracturing
treatment.
[0031] The debris control system 100 allows the DFIT or hydraulic
fracturing treatment to be performed/applied using the second
ported sub 104 without interference from the debris that has passed
through the first ported sub 102 to the formation 118, or that is
otherwise separated by the wiper plug 202. Without the debris
control system 100, cementing residue, pipe dope, or other debris
might obstruct the flow path from the wellbore to the formation,
making collected data uninterpretable, unreliable, or otherwise
causing the DFIT to fail. The debris in the wellbore would further
interfere with hydraulic fracturing treatments. Without the debris
control system 100, accumulated debris requires costly intervention
to remove.
[0032] FIG. 6 depicts a well completion system 600, in accordance
with some embodiments. Well completion occurs after the wellbore
602 has been drilled, but before the well 604 can be put into
production. Well completion can include many operations, such as
casing, cementing, perforating, gravel packing, production tree
installation, DFIT, hydraulic fracturing, among others.
[0033] Casing operations help ensure that the wellbore 602 will not
collapse when drilling fluids are removed from the wellbore 602 and
protect the drilling fluids from contamination by other materials
of the wellbore 602. The casing operations generally comprise
joining sections of tube (or joints), for example steel or other
metal, to form a casing 606. The casing 606 is then run into the
wellbore 602. Different diameters of casing 606 may be used at
different locations within the wellbore 602. For example, a casing
program may include production casing, intermediate casing, surface
casing, conductor casing, or the like, each comprising a different
diameter tube for the casing 606. An accurate casing program is
essential to ensuring that the well can flow properly given the
wellbore conditions.
[0034] The well completion system 600 further comprises the debris
control system 100 of FIGS. 1-3 installed at the toe of the casing
606. The guide shoe 114 guides the first joint of the casing 606
into the wellbore 602. After the debris control system 100 and any
other tools have been installed on the casing 606, the casing 606
is run to depth into the wellbore 602 and cementing operations
begin. Cement is pumped down the casing 606 to the guide shoe 114,
where it continues to flow up the annulus between the casing 606
and the wellbore 602, isolating the wellbore from the
formation.
[0035] The space between the guide shoe 114 and the float collar
116 (e.g., an auto-fill float collar) define a shoe track 612. The
purpose of the shoe track 612 is to avoid over-displacing cement
during cementing operations. The float collar 116 (e.g., an
auto-fill float collar) and the guide shoe 114 prevent reverse flow
of cement back into the casing after placement. The shoe track 612
may comprise a single section of the casing 606 or multiple joints
of the casing 606. In some applications, one or more centralizers
614, 615 keep the casing 606 off the wall of the wellbore 602 to
ensure proper cementing operations. Some applications may further
utilize scratchers to remove wall cake and ensure that the cement
bonds to the wall of the wellbore 602. In at least one embodiment,
the well completion system 600 comprises an open-hole
completion.
[0036] In at least one embodiment, the wiper dart 120 is used
during the initial cementing operation, to pass through the inner
diameter of the second landing collar 112, and landing at the first
landing collar 110. The wiper dart 120 activates the first landing
collar 110 and prevents cement slurry from flowing back into the
wellbore 602 (e.g., u-tubing) by sealing the wellbore 602 at the
first landing collar 110. The debris control system 100 may then be
used to clean the wellbore 602 and to facilitate performing DFITs
or hydraulic fracturing treatments.
[0037] In the foregoing Detailed Description, it can be seen that
various features are grouped together in a single embodiment for
the purpose of streamlining the disclosure. This method of
disclosure is not to be interpreted as reflecting an intention that
the claimed embodiments require more features than are expressly
recited in each claim. Rather, as the following claims reflect,
inventive subject matter lies in less than all features of a single
disclosed embodiment. Thus the following claims are hereby
incorporated into the Detailed Description, with each claim
standing on its own as a separate embodiment.
[0038] Note that not all of the activities or elements described
above in the general description are required, that a portion of a
specific activity or device may not be required, and that one or
more further activities may be performed, or elements included, in
addition to those described. Still further, the order in which
activities are listed are not necessarily the order in which they
are performed. Also, the concepts have been described with
reference to specific embodiments. However, one of ordinary skill
in the art appreciates that various modifications and changes can
be made without departing from the scope of the present disclosure
as set forth in the claims below. Accordingly, the specification
and figures are to be regarded in an illustrative rather than a
restrictive sense, and all such modifications are intended to be
included within the scope of the present disclosure.
[0039] Benefits, other advantages, and solutions to problems have
been described above with regard to specific embodiments. However,
the benefits, advantages, solutions to problems, and any feature(s)
that may cause any benefit, advantage, or solution to occur or
become more pronounced are not to be construed as a critical,
required, or essential feature of any or all the claims. Moreover,
the particular embodiments disclosed above are illustrative only,
as the disclosed subject matter may be modified and practiced in
different but equivalent manners apparent to those skilled in the
art having the benefit of the teachings herein. No limitations are
intended to the details of construction or design herein shown,
other than as described in the claims below. It is therefore
evident that the particular embodiments disclosed above may be
altered or modified and all such variations are considered within
the scope of the disclosed subject matter. Accordingly, the
protection sought herein is as set forth in the claims below.
* * * * *