U.S. patent application number 14/938065 was filed with the patent office on 2016-05-12 for multi-acting circulation tool for one-trip casing cut-and-pull.
The applicant listed for this patent is HydraWell Inc.. Invention is credited to Rodney D. Bennett, Martin P. Coronado, Luis A. Garcia, Markus Iuell, Mark E. Plante.
Application Number | 20160130901 14/938065 |
Document ID | / |
Family ID | 54608977 |
Filed Date | 2016-05-12 |
United States Patent
Application |
20160130901 |
Kind Code |
A1 |
Coronado; Martin P. ; et
al. |
May 12, 2016 |
Multi-Acting Circulation Tool for One-Trip Casing Cut-and-Pull
Abstract
Disclosed embodiments may relate to methods and devices which
may assist in removal of casing from a wellbore, for example during
abandonment operations. In an embodiment, the tool device may have
a sleeve rotationally disposed on a housing body, such that
rotation may operate to switch the tool between two configurations.
In the first configuration, the tool may allow fluid flow down the
length of the tool string through the longitudinal bore, and then
back up to the surface through the annular space outside the
housing. In the second configuration, the tool may allow fluid flow
from the bore of the tool to the annular space, and then downward
in the annular space.
Inventors: |
Coronado; Martin P.;
(Cypress, TX) ; Garcia; Luis A.; (Kingwood,
TX) ; Plante; Mark E.; (Tomball, TX) ; Iuell;
Markus; (Sola, NO) ; Bennett; Rodney D.;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HydraWell Inc. |
Houston |
TX |
US |
|
|
Family ID: |
54608977 |
Appl. No.: |
14/938065 |
Filed: |
November 11, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62078798 |
Nov 12, 2014 |
|
|
|
Current U.S.
Class: |
166/298 ;
166/185; 166/55.2 |
Current CPC
Class: |
E21B 29/002 20130101;
E21B 34/12 20130101; E21B 29/005 20130101 |
International
Class: |
E21B 29/00 20060101
E21B029/00; E21B 34/12 20060101 E21B034/12 |
Claims
1. A tool for use in a downhole tool string within a cased
wellbore, comprising: a mandrel housing configured to be made up as
part of the tool string, with a longitudinal bore therethrough, one
or more mandrel ports penetrating radially from the bore through
the housing, and a bypass element located above the one or more
mandrel ports and having one or more bypass ports therethrough; an
annular seal located about the exterior of the bypass element of
the housing and configured to sealingly engage the cased wellbore;
and a sleeve disposed on the exterior of the housing for rotational
movement with respect to the housing between a first position and a
second position; wherein: the sleeve comprises one or more radial
ports, a face flange operable to interface with the bypass element
to seal annular flow therethrough, and a rotational position
retaining element; the face flange comprises one or more annular
flow ports; in the first position, the radial ports in the sleeve
are not aligned with the mandrel ports in the housing body, but the
annular flow ports in the face flange are aligned with the bypass
ports in the bypass element; and in the second position, the radial
ports in the sleeve are aligned with the mandrel ports in the
housing body, but the annular flow ports in the face flange are not
aligned with the bypass ports in the bypass element of the
housing.
2. The tool of claim 1, wherein the sleeve is configured to open
and close the radial mandrel ports in the housing and the
longitudinal bypass ports in the bypass element of the housing in
an offsetting manner, such that when one is closed, the other is
open, and vice versa.
3. The tool of claim 1, wherein the tool is configured to be
operated by rotation of the housing.
4. The tool of claim 1, wherein the rotational position retaining
element comprises one or more drag blocks.
5. The tool of claim 1, wherein the sleeve is operable to rotate
with respect to the housing.
6. The tool of claim 1, wherein the annular seal is configured to
rotate freely with respect to the housing.
7. The tool of claim 1, wherein the longitudinal bore of the
housing comprises a necked-down portion with a smaller inner
diameter forming a shoulder, and wherein the shoulder is located
below the mandrel ports.
8. The tool of claim 1, wherein the sleeve is biased upward against
the bypass element.
9. The tool of claim 1, further comprising stabilizer elements
operable to help centralize the tool in the cased wellbore.
10. The tool of claim 1, wherein the tool string further comprises
a cutter and a motor, wherein the motor powers the cutter, wherein
the motor and cutter are located below the mandrel ports, and
wherein the motor is configured to be powered by fluid flow through
the bore, which then circulates back to the surface through the
annular space.
11. The tool of claim 1, wherein the tool string further comprising
a spear.
12. The tool of claim 11, wherein the spear comprises a rotatable,
resettable spear.
13. The tool of claim 10, wherein the tool string further comprises
one or more magnets located below the mandrel ports and above the
cutter.
14. A method of extracting casing from a wellbore, comprising the
steps of: forming up a tool string having a longitudinal bore
therethrough comprising a resettable spear, a cutter, a motor
configured to power the cutter, and a tool for selectively
diverting fluid flow from the longitudinal bore to an annular space
between the tool and the cased wellbore via one or more mandrel
ports and selectively allowing fluid flow upward in the annular
space above the tool via one or more bypass ports, with the tool
having a first position with the mandrel ports closed and the
bypass ports open, and a second position with the mandrel ports
open and the bypass ports closed; wherein: the tool is operable to
be changed from the first position to the second position by
rotation; and the motor and cutter are located below the tool in
the tool string.
15. The method of claim 14, further comprising: running the tool
string downhole in the cased wellbore; setting the spear by
rotation of the tool string; placing the tool in the first
configuration by rotation; making a cut to the casing of the cased
wellbore; and placing the tool in the second configuration by
rotation opposite that used to position the tool in the first
position.
16. The method of claim 15, wherein a single rotation of the tool
string sets the spear and places the tool in the first
configuration.
17. The method of claim 16, wherein the cut is made by rotating the
tool string in the direction for setting the spear and positioning
the tool in the first position, while pumping fluid down the bore
of the tool string to power the motor.
18. The method of claim 15, further comprising overpulling the tool
string after the spear has been set and before making the cut.
19. The method of claim 15, further comprising: dropping a ball to
seal the longitudinal bore below the mandrel ports of the tool and
above the cutter and motor; and flowing fluid through the bore,
through the mandrel ports of the tool, and down to the cut in the
casing.
20. The method of claim 19, further comprising: unsetting the spear
by rotating the tool string in the opposite direction used to set
the spear; placing the tool in the first configuration by the same
rotation used to unset the spear; reverse pumping the well to
extract the ball; repositioning the tool string in the well at a
new depth; re-setting the spear, and placing the tool by rotation
to its first configuration; making a subsequent cut at the new
depth in the well; placing the tool by rotation to its second
configuration; dropping the ball to seal the bore below the mandrel
ports of the tool and above the cutter and motor; and flowing fluid
through the bore, through the mandrel ports of the tool, down to
the subsequent cut in the casing.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a non-provisional of and claims benefit
under 35 U.S.C. .sctn.119 to co-pending U.S. Provisional Patent
Application Ser. No. 62/078,798, filed on Nov. 12, 2014, and
entitled "Multi-Acting Circulation Tool for One-Trip Casing
Cut-and-Pull", which is hereby incorporated by reference for all
purposes as if reproduced in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
REFERENCE TO A MICROFICHE APPENDIX
[0003] Not applicable.
BACKGROUND
[0004] Applicants have developed tool embodiments allowing for
selective diversion of fluid flow within a wellbore/tool string.
Such disclosed embodiments may allow for more efficient ways to
remove casing from wellbores during well abandonment operations,
for example. By way of illustration, disclosed embodiments may
relate to tools to assist in cutting and removing casing in advance
of extraction, allowing for the related cutting and pulling
operations to take place during a single trip of the tool string
downhole. And disclosed embodiments may also allow for tool
configuration (and thus fluid flow paths) to be altered multiple
times during a single trip downhole, for example if more than one
cutting operation is needed for casing removal. Persons of skill
will appreciate the advantages arising from such tool embodiments
described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] For a more complete understanding of the present disclosure,
reference is now made to the following brief description, taken in
connection with the accompanying drawings and detailed description,
wherein like reference numerals represent like parts.
[0006] FIG. 1A illustrates, as a longitudinal cross-section view,
an exemplary embodiment of a tool in its first configuration (e.g.
with the sleeve located in its first position rotationally with
respect to the housing/mandrel);
[0007] FIG. 1AA illustrates a lateral/radial cross-section of FIG.
1A (taken at F-F), showing alignment of the annular flow ports in
the face flange/seal with the bypass ports (e.g. to allow fluid
flow in the annular space, since the bypass is open);
[0008] FIG. 1AB illustrates a lateral/radial cross-section of FIG.
1A (taken at D-D), showing the rotational position retaining
element;
[0009] FIG. 1AC illustrates a lateral/radial cross-section of FIG.
1A (taken at E-E), showing the stabilizer elements;
[0010] FIG. 1AD is a detail of the bypass ports of FIG. 1A;
[0011] FIG. 1B illustrates, as a partial longitudinal cross-section
view, the tool embodiment of FIG. 1A in its second configuration
(e.g. with the sleeve located in its second position rotationally
with respect to the housing/mandrel);
[0012] FIG. 1BA illustrates a lateral/cross-section view of FIG. 1B
(taken at K-K), showing that the annular flow ports in the face
flange/seal are out of alignment with the bypass ports (e.g. so
there can be no fluid flow upward in the annular space beyond the
bypass element, since the bypass is closed);
[0013] FIG. 1BB illustrates a lateral/cross-section view of FIG. 1B
(taken at L-L), showing alignment of the radial ports with the
mandrel ports to allow radial flow of fluid from the bore to the
annular space);
[0014] FIG. 1BC illustrates a detail (cut-away) portion of the
sleeve in perspective view, showing the rotational position
retaining element of the sleeve in more detail;
[0015] FIG. 2 illustrates schematically a tool string with an
exemplary tool (such as the tool of FIG. 1A for example) located
with a cased wellbore;
[0016] FIGS. 3A-3C illustrate schematically an exemplary tool in
its first configuration (e.g. with the sleeve in its first
position, sealing the mandrel ports and aligning the annular flow
ports with the bypass ports to allow annular fluid flow), with FIG.
3A illustrating in longitudinal cross-section an exemplary fluid
flow for such a configuration, FIG. 3B illustrating in cut-away
side view how the sleeve blocks/seals the mandrel port(s) in the
first configuration/position, and FIG. 3C illustrating in radial
cross-sectional view how the annular flow ports are aligned with
the bypass ports in the first configuration;
[0017] FIGS. 4A-4D illustrate schematically an exemplary tool in
its second configuration (e.g. with the sleeve in its second
position, sealing the bypass (with the annular flow ports out of
alignment with the bypass ports) while allowing radial flow from
the bore to the annular space), with FIG. 4A illustrating in
longitudinal cross-section an exemplary fluid flow for such a
configuration, FIG. 4B illustrating in cut-away side view alignment
of the radial ports of the sleeve with the mandrel ports in the
second configuration, and FIG. 4C illustrating in radial
cross-section view how the annular flow ports are out of alignment
with the bypass ports (thereby preventing annular fluid flow
upward) in the second configuration;
[0018] FIG. 4D is a schematic illustration similar to that of FIG.
4A (showing the tool in its second configuration), in which the
tool and tool string are shown in place within the casing of the
wellbore, the cut of the casing is shown, and the fluid flow (down
the bore, out the aligned radial and mandrel ports and into the
annular space, downward in the annular space, out the cut, and
upward from the cut in the space between the casing and the
wellbore) of the second configuration is more fully
illustrated;
[0019] FIG. 5 illustrates schematically the tool string moved
upward in the cased wellbore and configured (in its first
configuration) to make a second/subsequent cut of the casing;
[0020] FIG. 6 illustrates schematically the tool string in its
second configuration after making the second/subsequent cut of the
casing; and
[0021] FIG. 7 illustrates schematically the tool string pulling the
cut casing from the wellbore.
DETAILED DESCRIPTION
[0022] It should be understood at the outset that although
illustrative implementations of one or more embodiments are
illustrated below, the disclosed systems and methods may be
implemented using any number of techniques, whether currently known
or not yet in existence. The disclosure should in no way be limited
to the illustrative implementations, drawings, and techniques
illustrated below, but may be modified within the scope of the
appended claims along with their full scope of equivalents.
[0023] The following brief definition of terms shall apply
throughout the application:
[0024] The term "up", "uphole", "above", or the like, when used in
reference to well or the tool string for example, shall mean
towards the surface or towards the top or away from the end of the
well; similarly, the term "down", "downhole", "below", or the like
shall mean away from the surface or towards the bottom or end of
the well;
[0025] The term "comprising" means including but not limited to,
and should be interpreted in the manner it is typically used in the
patent context;
[0026] The phrases "in one embodiment," "according to one
embodiment," and the like generally mean that the particular
feature, structure, or characteristic following the phrase may be
included in at least one embodiment of the present invention, and
may be included in more than one embodiment of the present
invention (importantly, such phrases do not necessarily refer to
the same embodiment);
[0027] If the specification describes something as "exemplary" or
an "example," it should be understood that refers to a
non-exclusive example;
[0028] The terms "about" or approximately" or the like, when used
with a number, may mean that specific number, or alternatively, a
range in proximity to the specific number, as understood by persons
of skill in the art field (for example, +/-10%); and
[0029] If the specification states a component or feature "may,"
"can," "could," "should," "would," "preferably," "possibly,"
"typically," "optionally," "for example," "often," or "might" (or
other such language) be included or have a characteristic, that
particular component or feature is not required to be included or
to have the characteristic. Such component or feature may be
optionally included in some embodiments, or it may be excluded.
[0030] Embodiments may relate generally to methods and devices
which may assist in removal of casing from a wellbore, for example
during abandonment operations. More specifically, the device and
method embodiments might relate to cutting of the casing, cleanout
operations to loosen the casing in the wellbore (by, for example,
flowing fluid between the casing and the surface of the wellbore),
and/or extraction of the cut casing from the wellbore. And
typically, the device and method embodiments might allow such
cutting-and-pulling operations to be performed using only one trip
of the tool string downhole (e.g. performed in a single trip, for
additional efficiency, thereby offering the potential to save
significant money), for example by selectively diverting fluid
flow.
[0031] So, disclosed embodiments may relate generally to tool
embodiments for diversion of fluid flow, typically within a
wellbore and/or tool string. In some instances, typical embodiments
of such diverter tools may relate to casing cutting and pulling
operations as currently performed in well abandonment operations.
Typically, the casing is cut at a predetermined depth where the
casing string above must be removed from the well, so that adequate
well barriers can be put in place to secure the well. The casing
cut may be performed using an expanding-blade cutter, which
typically may be rotated by the work string, or alternatively by a
positive displacement mud motor run directly above the cutter in
the tool string. The motor typically is powered by fluid circulated
through the drill pipe work string (e.g. tool string), which passes
through the motor. This motor's stator/rotor combination may create
rotation and torque to power the cutter. Fluid typically then would
exit the cutter when in operation and would be circulated back up
the casing to the surface. Once the cut has been completed, the
cutting string would conventionally be removed from the well. The
next operation typically might be to circulate fluid around the
outside of the casing which was previously cut to remove old
drilling mud and any solids which may prevent or otherwise hinder
the casing from being removed from the well. To perform this
operation conventionally (e.g. without a disclosed diverter tool),
a second tool string would be run in the well, which includes a
casing pack off tool and a casing spear. Once the spear is latched
into the casing, the casing pack off prevents fluid circulation up
hole through the annulus between the casing that has been cut and
the drill pipe. So, as fluid is pumped down the drill pipe it can
only go out through the cut in the casing and around the outside of
the casing that was cut. This would provide the necessary
circulation around the outside of the casing to remove mud, debris
and gas before pulling the casing. Once clean out circulation has
been completed, the spear and jars would be used to pull the casing
from the well. The conventional process described above is
completed in two drill pipe/tool trips into the well, due to the
need to circulate fluids up the casing-drill pipe annulus while
making the casing cut, while then needing this annulus to be closed
off to allow clean-up circulation around the outside of the casing
after the cut has been made. The presently disclosed diverter tool
embodiments allow for this operation to be performed in only one
trip using a selective annular sealing device that would allow
circulation in the casing-drill pipe annulus during the cut, but
then be able to seal off the annulus (to prevent fluid upflow)
after the cut has been made. Performing this cutting and pulling
operation in only one trip should save substantial rig time and be
more cost effective for the operator. Furthermore, disclosed
embodiments may also allow for tool configuration (and thus fluid
flow paths) to be altered multiple times during a single trip
downhole, for example if more than one cutting operation is needed
for casing removal (such that multiple cuts might be performed in a
single trip downhole). Thus, disclosed tool embodiments represent
significant improvements for such casing cut-and-pull
operations.
[0032] In such embodiments, the tool device may have a sleeve
rotationally disposed on a mandrel/housing body, such that rotation
(for example, rotation of the tool string from the surface) may
operate to selectively switch the tool between two configurations
(for example, by moving the sleeve from a first position to a
second position). In the first configuration, the tool may allow
fluid flow down the length of the tool string through the
longitudinal bore (for example, in order to power cutting of the
casing), and then back up to the surface through the annular space
outside the housing (within the casing--e.g. between the housing
and the casing). So in the first configuration, the tool typically
allows for cutting of the casing (by for example, directing fluid
in the bore downward to the motor for the cutter and allowing
circulation back to the surface in the annular space (between the
tool string and the casing)). In the second configuration, the tool
may allow fluid flow from the bore of the tool to the annular
space, and then downward (for example, towards the cut). This may
allow fluid to exit the cut and flow upward on the outside of the
casing (e.g. between the casing and the wellbore surface). The goal
might be to circulate fluid up the outside of the casing all the
way to the surface, for example in order to loosen the casing
within the wellbore to improve extraction of the casing from the
wellbore. So in the second configuration, the tool typically allows
for circulation through the cut and upward between the casing and
the wellbore (for example, by sealing the annular space between the
housing of the tool and the casing and opening flow radially from
the bore to the annular space (for example, below the location of
the sealed section of the annular space)). And by using the
rotational position of the sleeve with respect to the housing to
set the configuration of the tool, the tool configuration is
operable to switch (between the first and second
configuration/position) multiple times if desired.
[0033] So for example, disclosed embodiments might include a tool
for use in a downhole tool string within a cased wellbore,
comprising: a housing/mandrel adapted to be made up as part of the
tool string, with a longitudinal bore therethrough, one or more
mandrel ports penetrating radially from the longitudinal bore
through the housing (operable to allow fluid flow from the bore to
the annular space between the housing and the casing), and a bypass
element located above the one or more mandrel ports and having one
or more bypass ports therethrough (operable to allow fluid flow in
the annular space (e.g. annular flow between the housing and the
casing) from below the bypass element to above the bypass element);
a packer cup (or other annulus seal element) typically located
about/around the exterior of the bypass element of the housing and
operable to engage (in a sealing manner) the casing (e.g. cased
wellbore) and/or the bypass element (for example, to prevent fluid
flow between the exterior of the bypass element and the cased
wellbore--it should be understood that the term "packer cup" as
used in this application is intended to be broadly considered as
any annulus seal element and is not merely limited to any specific
packer cup embodiment, so the terms "packer cup" and "annulus seal
element" may be used interchangeably herein); and a sleeve disposed
on the exterior of the housing for rotational movement with respect
to the housing between a first position and a second position.
Typically, the sleeve would comprise one or more radial ports
(corresponding to the mandrel ports in the housing body and/or
located on the same radial plane as the mandrel ports in the
housing and/or spaced about the circumference of the sleeve in a
manner corresponding/matching the spacing of the mandrel ports in
the housing), a face flange/seal operable to interface/engage with
the bypass element to seal annular flow therethrough, and a
rotational position retaining element (operable to restrict
rotational movement of the sleeve). For example, the rotational
position retaining element might comprise two or more drag blocks
(e.g. having spring loaded dog elements that hold/grip the casing
to restrict rotation of the sleeve--so that when the housing/tool
string is rotated, the sleeve does not rotate (or does not rotate
as much, thereby imparting a rotational offset between the
housing/tool string and the sleeve)). Additionally, the face/flange
seal typically would comprise one or more annular flow ports
(corresponding to the bypass ports and/or located in a
longitudinally adjacent plane as the bypass ports and/or spaced
about the circumference of the face seal in a manner
corresponding/matching the spacing of the bypass ports). In the
first position of the sleeve, the radial ports in the sleeve would
not be aligned with the mandrel ports in the housing body (such
that the sleeve closes/seals the mandrel ports in the housing to
prevent (radial) fluid flow from the bore to the annular space
through the housing), but the annular flow ports in the face seal
would be aligned with the bypass ports in the bypass element (such
that fluid may flow (longitudinally) through the packer cup/bypass
element in the annular space between the housing and the
casing--e.g. allowing fluid communication in the annular space from
below the packer cup to above the packer cup). In the second
position of the sleeve, the radial ports in the sleeve would be
aligned with the mandrel ports in the housing body (allowing
(radial) fluid communication from the bore to the annular space,
such that fluid in the bore may flow into the annular space), but
the annular flow ports in the face seal would not be aligned with
the bypass ports in the bypass element of the housing (such that
the face flange/seal closes/seals the bypass ports to prevent
(longitudinal) fluid flow in the annular space from below the
packer cup to above the packer cup--e.g. the tool no longer allows
annular fluid flow upward past the sealed packer cup/bypass
element, since the bypass element would be closed). In other words,
typically the sleeve would be operable to open and close the radial
mandrel ports in the housing and the longitudinal bypass ports in
the bypass element of the housing in an offsetting manner, such
that when one is closed, the other is open, and vice versa. So for
example, in some embodiments the two different types of ports in
the tool (e.g. relating to radial flow from the bore to the annular
space and relating to longitudinal flow in the annular space, for
example upward past the bypass element) might have a 90 degree
offset.
[0034] Typically, the tool would be operated by rotation of the
housing (e.g. via rotation of the tool string), for example with
respect to the sleeve (such that rotation of the position of the
sleeve with respect to the housing would operate to shift the tool
between configurations). In other words, rotation of the tool
string one direction would typically position the sleeve in the
first position (corresponding to the first configuration for the
tool, for example), and rotation of the tool string the other
direction would typically position the sleeve in the second
position (corresponding to the second configuration for the tool,
for example). So for example, the tool might be configured so that
a right hand turn/rotation of the housing/tool string operates to
place the sleeve in the first position (with bypass ports open
(e.g. the annular flow ports of the sleeve aligned with the bypass
ports) and mandrel ports in the housing closed (e.g. the radial
ports of the sleeve out of alignment with the mandrel ports in the
housing)), and a left hand turn/rotation of the housing/tool string
operates to place the sleeve in the second position (e.g. close the
bypass ports (e.g. the annular flow ports of the sleeve out of
alignment with the bypass ports) and open the mandrel ports in the
housing (e.g. the radial ports of the sleeve are aligned with the
mandrel ports in the housing)).
[0035] Typically, the tool may be configured so that the sleeve is
free (operable) to rotate with respect to the housing. In some
embodiments, the sleeve would be operable to rotate approximately
90 degrees with respect to the housing. Often, the rotation of the
sleeve with respect to the housing would be limited (e.g. allowing
only a set amount of such rotation, before the sleeve would rotate
with the housing). For example, the interface between the sleeve
and the housing may include a stop element or mechanism, so that
after a pre-defined amount of rotation of the sleeve with respect
to the housing in one direction, the sleeve would rotate with the
housing if additional rotation that direction occurs (and vice
versa, the other direction). So for example, in some embodiments
the sleeve's rotation might be limited to approximately 90 degree
rotation with respect to the housing (e.g. so that the sleeve is
operable to rotate approximately 90 degrees in shifting between its
two positions/configurations). For example, one or more bolts (on
the bypass element, for example) might be located (for sliding)
within slots (which in some embodiments might be the annular flow
ports) in the face flange that govern the allowed amount of
rotation of the sleeve with respect to the housing.
[0036] In some embodiments, the packer cup (or other annulus seal
element) may be configured to rotate freely (e.g.
configured/operable for free rotation) with respect to the
housing/bypass element. And typically, the longitudinal bore of the
housing would also comprise a necked-down portion (e.g. with a
smaller inner diameter) having a shoulder, typically located below
the mandrel ports. This shoulder within the bore may serve as a
ball/plug seat (for example, if a ball is dropped to seal the
longitudinal bore, which might be useful to ensure full diversion
of fluid from the bore to the annular space when the tool is in its
second configuration). As used herein, ball is intended to be
understood broadly as including any such plug element for blocking
fluid flow through the longitudinal bore (for example, sealing the
longitudinal bore after being pumped down to seat on a
shoulder)).
[0037] Typically, the sleeve or face seal/flange of such
embodiments might be biased upward against the bypass element. In
other words, an exemplary tool might further comprise a spring,
with the spring biasing the sleeve (or face flange) upward into
contact with the bypass element (for example, to ensure a good seal
therebetween). And some embodiments might further comprise
stabilizer elements operable to help centralize the tool in the
cased wellbore. Typically, such stabilizer elements would be
configured to (freely) rotate with respect to the housing.
[0038] In use, the tool might often be used with a ball or plug
element which is operable to seal the longitudinal bore, for
example by seating on the shoulder of the necked-down portion of
the longitudinal bore. Typically such a ball or plug might be used
when the sleeve is in the second position (e.g. the tool is in its
second configuration), to divert/direct fluid flow from the bore
entirely through the mandrel ports and into the annular space. So
the ball would be a separate element, distinct and apart from the
housing/tool, which might be used in conjunction with the tool in
only certain configurations to help direct/divert fluid flow. For
example, prior to placement of the ball on the shoulder in the bore
(e.g. when the longitudinal bore is open), all fluid pumped down
the bore would typically flow entirely through the bore (e.g. below
the tool in the tool string), but after placement of the ball on
the shoulder in the bore (and when the tool is in its second
configuration), fluid would flow entirely through the mandrel
ports.
[0039] Typically, the tool would be made up into a tool string for
use downhole. Such a tool string would typically include other
elements. For example, a tool string (comprising the tool) might
further comprising a cutter (for example, an expanding-blade
cutter) and a motor, with the motor powering/driving the cutter and
the motor being operable/configured to be powered/driven by fluid
flow through the tool string (e.g. bore). In typical tool string
embodiments, the motor and cutter would be located below the
mandrel ports (e.g. below the tool). Additionally, the tool string
would typically further comprise a spear (or other pulling tool for
extracting the cut casing--as used herein, spear is intended to be
interpreted broadly to include an actual downhole spear and/or any
other such pulling tool for extracting cut casing from a wellbore).
In embodiments, the spear might comprise a rotatable, resettable
spear. Thus, the spear might be configured to be set with rotation
of the tool string one direction (typically in the same direction
as used to place the tool in its first configuration, for example
to the right) and unset by rotation of the tool string the other
direction (typically in the same direction used to place the tool
in its second configuration, for example to the left). And in some
embodiments, the tool string might also optionally include one or
more magnets (e.g. located below the mandrel ports and/or above the
cutter). Such magnets might be operable to capture any loose
cutting shavings from the fluid flow (for example, before it
circulates up to the tool (for example, the bypass ports of the
tool)) and/or to the surface.
[0040] FIGS. 1A-1B illustrates an exemplary embodiment of a tool
device, with FIG. 1A showing the tool 100 in its first
configuration (e.g. with the sleeve 140 in its first position), and
FIG. 1B showing the tool 100 in its second configuration (e.g. with
the sleeve 140 in its second position). The tool 100 would
typically be shifted between its first and second configurations
based on rotation of the sleeve 140 with respect to the housing 110
(for example, by rotating the housing by rotation of the tool
string from the surface, while the sleeve's rotational position is
retained/restrained to provide rotational offset). In the
embodiment of FIGS. 1A and 1B for example, the tool may be moved
into its first configuration by right hand rotation, and may be
moved into its second configuration by left hand rotation. In other
words the tool of FIGS. 1A-B is configured so that a right hand
turn/rotation of the housing/tool string operates to place the
sleeve in the first position (with bypass ports open (e.g. the
annular flow ports of the sleeve aligned with the bypass ports) and
mandrel ports in the housing closed (e.g. the radial ports of the
sleeve out of alignment with the mandrel ports in the housing)),
and a left hand turn/rotation of the housing/tool string operates
to place the sleeve in the second position (e.g. close the bypass
ports (e.g. the annular flow ports of the sleeve out of alignment
with the bypass ports) and open the mandrel ports in the housing
(e.g. the radial ports of the sleeve are aligned with the mandrel
ports in the housing)). In the embodiment of FIGS. 1A-B,
approximately 90 degrees of rotation would operate to switch the
tool between configurations. FIGS. 1AA, 1AB, 1AC, 1AD, 1BA, 1BB,
and 1BC are related to FIGS. 1A and 1B and may help to further
illustrate aspects/elements of the tool in either the first or
second configuration (as will be discussed in greater detail
below).
[0041] So in FIG. 1A, the tool 100 comprises a housing 110, which
has a longitudinal bore 115 therethrough and one or more mandrel
ports 117 (penetrating the housing/mandrel 110 radially, for
example to provide a flow path outward from the bore 115 towards
the annular space outside the housing). The housing 110 of FIG. 1A
has an outer diameter which is less than the inner diameter of the
casing of the wellbore to be serviced. The housing 110 also is
configured so that it may be made-up into a tool string (for
example having threaded portions on the top and/or bottom sections
allowing for mating with other tool string elements). In FIG. 1A, a
portion of the housing is the bypass element 120, which contains
one or more bypass ports 125 (as seen, for example in FIG. 1AA)
extending in the longitudinal direction through the bypass element
120 (thereby providing a flow path for the annular space 182 which
may be schematically parallel to the longitudinal bore 115, as
shown in FIGS. 2-3A-3C for example). And located about the bypass
element 120 is a packer cup 130. The packer cup 130 forms a seal
about the bypass element 120 (at the contact points about the
circumference), and is operable to form a seal with the casing 180
when the tool 100 is in place within a cased wellbore (with its
inner diameter being approximately equal to that of the bypass
element and with its outer diameter being approximately equal to
the inner diameter of the casing, as FIG. 2 illustrates for
example). Thus, when the tool 100 is in place in the cased
wellbore, the packer cup 130 prevents any flow past (the exterior
of) the bypass element 120 (e.g. the packer cup 130 may seal the
annular space about the bypass element). In other words, the bypass
ports 125 in the bypass element 120 are the only avenue for annular
flow in the annular space, due to sealing engagement of the packer
cup 130 with the cased wellbore. In the embodiment of FIG. 1, the
packer cup 130 may be free to rotate about the bypass element
120.
[0042] Located about the exterior of the housing 110 of FIG. 1A is
a sleeve 140, which is operable to rotate with respect to the
housing 110. Rotation of the sleeve (from a first position to a
second position) may operate to move the tool from its first
configuration (shown in FIG. 1A) to its second configuration (shown
in FIG. 1B). The sleeve 140 of FIG. 1A is typically located
longitudinally so that it can interface with the mandrel ports 117
and the bypass element 120 (such that, for example, the sleeve 140
spans a distance downward from the bypass element 120 to at least
below the mandrel ports 117). The sleeve 140 also comprises one or
more radial ports 142, which typically are located on the same
radial plane (e.g. the same longitudinal distance downward along
the tool string) as the mandrel port(s) 117, and which are
typically spaced about the circumference of the sleeve 140 in a
manner corresponding to the spacing of the mandrel ports 117 on the
circumference of the housing 110 (and typically, the radial ports
might be sized to match the corresponding mandrel ports). Such
location and spacing allows the radial ports 142 of the sleeve to
either be aligned with the mandrel ports 117 (e.g. so the sleeve
can open the mandrel ports, for example in the second rotational
position of the sleeve), or allows the radial ports 142 to be out
of alignment with the mandrel ports (e.g. so the sleeve can close
the mandrel ports, for example in the first rotational position of
the sleeve). In other words, the radial ports 142 are located and
spaced on the sleeve 140 so that rotation of the sleeve may be used
to open or close the mandrel ports (depending on the alignment of
the radial ports with the mandrel ports).
[0043] Additionally, the sleeve 140 of FIG. 1A comprises a face
flange/seal 144, which is typically located on the upper end of the
sleeve 140 and typically has a larger outer diameter than the
portion of the sleeve 140 having the radial ports 142. In other
words, the face flange/seal 144 of FIG. 1A extends out laterally
from the upper end of the main sleeve body. The face flange/seal
144 comprises one or more annular flow ports 145, which are located
and spaced on the face flange 144 in a manner corresponding to the
spacing of the bypass ports 125 in the bypass element 120 of the
housing (and typically, the annular flow ports might be sized to be
at least as large as (and often larger than) the corresponding
bypass ports). Such location and spacing allows the annular flow
ports 145 of the sleeve to either be aligned with the bypass ports
125 (e.g. so the sleeve can open the bypass ports, for example in
the first rotational position of the sleeve), or allows the annular
flow ports 145 to be out of alignment with the bypass ports 125
(e.g. so the sleeve can close the bypass ports, for example in the
second rotational position of the sleeve). In other words, the
annular flow ports 145 are located and spaced on the face flange
144 of the sleeve so that rotation of the sleeve may be used to
open or close the bypass ports 125 (depending on the alignment of
the annular flow ports with the bypass ports). The annular flow
ports 145 of FIGS. 1A and 1B are radially offset from the radial
ports 142 of the sleeve, so that when one set of ports are aligned
to open flow in one direction, the other set of ports are out of
alignment to prevent flow the other direction (and vice versa).
Alternatively, the mandrel ports of the housing and the bypass
ports might be radially offset. Regardless, the open position for
the bypass ports should typically be radially offset from the open
position for the mandrel ports. In FIG. 1A, for example, these
ports have a 90 degree offset (which may correspond to the maximum
allowed rotation of the sleeve with respect to the housing in some
embodiments). For example, when the radial ports 142 are aligned
with the mandrel ports 117 (to allow flow radially from the bore
outward), the annular flow ports 145 would be out of alignment with
the bypass ports 125 (to block/prevent longitudinal annular flow
upward in the annular space beyond the bypass element 120). And
when the annular flow ports 145 are aligned with the bypass ports
125 (to allow longitudinal annular flow upward through the bypass
element), the radial ports 142 would be out of alignment with the
mandrel ports 117 (to block/prevent radial flow outward from the
bore through the housing). The upper surface of the sleeve/face
flange 144 may also have sealing properties, so that when the
annular flow ports are out of alignment with the bypass ports, the
face flange 144 may interface with the bypass element to form an
effect seal (blocking/sealing the bypass ports to prevent annular
flow therethrough).
[0044] In FIGS. 1A-1B, the sleeve 140 may be limited to only a
certain amount of rotation with respect to the housing 110. For
example, the sleeve 140 of FIG. 1A may be limited to approximately
90 degrees of rotation with respect to the housing 110. In the tool
of FIGS. 1A-B, this limited rotation may result from the
interaction of one or more bolts (for example extending from the
bypass element) with one or more corresponding slots (for example,
the annular flow ports in the face flange 144). This type of
interaction may be better seen in FIGS. 1AA and 1BA. For example,
in FIGS. 1AA and 1BA, the annular flow ports 145 may be slots (for
example, openings that are the same width as the bypass ports, but
are elongated to form a longer arc than the bypass ports), and
bolts 127 may extend from the bypass element 125 (downward) through
the slots (e.g. annular flow ports). Thus, the bolts 127 would
limit the amount of rotation of the sleeve with respect to the
housing (and bypass element) to approximately 90 degrees. FIG. 1AA
shows the annular flow ports/slots 145 when they are aligned with
the bypass ports 125 (e.g. the first configuration of the tool),
for example after maximum allowed right hand rotation (of the
sleeve with respect to the housing). FIG. 1BA shows the annular
flow ports/slots 145 when they are out of alignment with the bypass
ports 125 (not shown, since blocked by the face flange 144) (e.g.
the second configuration of the tool), for example after maximum
allowed left hand rotation (of the sleeve with respect to the
housing). So, the bolts in the slots might operate as a stop
mechanism, allowing only limited range of rotational movement of
the sleeve with respect to the housing in order to alter the tool
configuration. Any further rotation of the housing/tool string
beyond that point would result in the sleeve and housing rotating
together (for example, during cutting).
[0045] Furthermore, the sleeve 140 of FIG. 1A comprises a
rotational position retaining/restraining element 147, which is
operable to restrict rotational movement of the sleeve. In
practice, the rotational position retaining element 147 may
engage/interact with the casing (for example, causing
drag/friction) to limit movement of the sleeve 140 during rotation
of the tool string/housing. This allows the sleeve 140 to rotate
with respect to the tool housing 110, when the tool string is
rotated, and may allow for rotation of the tool string/housing to
be used to shift the tool from its first configuration to its
second configuration (and vice versa), for example by altering the
rotational position of the sleeve 140 with respect to the housing
110. Typically, the grip of such a rotational position retaining
element would be loose enough so that once the sleeve rotation
reaches its maximum offset in one direction with respect to the
housing (i.e. hits the stop mechanism), the tool string might still
be capable of rotation (for example, with the rotational position
retaining element slipping during cutting). In FIG. 1A, the
rotational position retaining element 147 may comprise one or more
(typically a plurality of) spring loaded dog elements 148, operable
to push outward against the casing during use of the tool. FIGS.
1AB and 1BC further illustrate such dog elements 148. The dog
elements typically provide frictional resistance to rotation
relative to the casing, similar to a brake pad against a rotor in
automotive applications. The dog elements 148 of FIGS. 1AB and 1BC
typically would be recessed into pockets within the sleeve and
would be energized (e.g. pressed outward) against the casing via
internal spring members. Additionally, the sleeve 140 may typically
be biased upward so that the face flange/seal 144 of the sleeve 140
may be in (sealing) contact with the bypass element (helping to
provide an effective seal), and in FIG. 1A (compression) spring 150
provides this biasing force. The spring 150 typically would be
compressed during assembly of the tool and would remain in
compression during operation. The spring typically outputs enough
force to maintain the face flange seal energized (e.g. pressed up
against the bypass element). The spring design can be one of many
different types (e.g. coil, bellville washer stack, wave, etc.). By
using a spring or other biasing mechanism to hold the face flange
144 in (sealing) contact with the bypass element, the sleeve may be
shifted downward by sufficient downward fluid pressure in the
annulus (for example, allowing reverse pumping to dislodge the ball
from the shoulder within the bore of the housing if it is desirable
to re-open the sealed bore), while preventing upward flow in the
annulus above the bypass element. In alternate embodiments (in
which such reverse circulation may not be desired), the sleeve
might instead have its longitudinal position fixed with respect to
the housing/bypass element.
[0046] The tool 100 (and/or the tool string 102) of FIG. 1A also
may comprise stabilizer elements 160, which may be operable to help
centralize the tool/tool string in the cased wellbore. In FIG. 1A,
the stabilizer elements 160 comprise a plurality of fins extending
outward to approximately the casing inner diameter. And in FIG. 1A,
the stabilizer elements may be free to rotate about the housing.
FIG. 1AC may further illustrate such stabilizer elements 160. And
in FIG. 1A, the longitudinal bore is not of uniform diameter
through the entire length of the housing 110, but further includes
a necked-down portion (e.g. having a smaller diameter than portions
of the bore located above the necked-down portion) forming a
shoulder 116. This shoulder 116 in the bore 115 may operate/serve
as a ball/plug seat during operation of the tool downhole, allowing
a ball/plug to be dropped/pumped downhole to seat on the shoulder
to seal the bore (preventing flow further down the longitudinal
bore 115).
[0047] So, the tool of FIGS. 1A-B has two configurations, based on
rotation (rotational position) of the sleeve with respect to the
housing. The sleeve is operable to open and close the radial
mandrel ports in the housing and the longitudinal bypass ports in
the bypass element of the housing based on its rotational position
with respect to the housing (moving from the first to the second
configuration), in an offsetting manner (such that when one is
closed, the other is open, and vice versa). FIG. 1A illustrates the
tool 100 in the first configuration, with the sleeve in its first
position. In the first position (of the sleeve), the radial ports
142 in the sleeve are not aligned with the mandrel ports 117 in the
housing body (such that the sleeve closes/seals the mandrel ports
in the housing to prevent fluid flow from the bore to the annular
space through the housing), but the annular flow ports 145 in the
face seal 144 are aligned with the bypass ports 125 in the bypass
element 120 (see for example FIG. 1AA, such that fluid may flow
through the packer cup/bypass element in the annular space between
the housing and the casing--e.g. allowing fluid communication in
the annular space from below the packer cup to above the packer
cup). In the first configuration, fluid flow in the bore 115 is
contained in the bore until exiting the tool/tool string (for
example, at the bottom end of the tool string), and fluid may flow
in the annular space without restriction (see for example, FIGS.
3A-3C).
[0048] FIG. 1B illustrates the tool 100 in the second
configuration, with the sleeve in its second position. In the
second position of the sleeve 140, the radial ports 142 in the
sleeve are aligned with the mandrel ports 117 in the housing body
(see FIG. 1BB for example, allowing fluid communication from the
bore to the annular space, such that fluid in the bore may flow
into the annular space), but the annular flow ports 145 in the face
seal 144 are not aligned with the bypass ports 125 in the bypass
element 120 of the housing (see FIG. 1BA for example, such that the
face/flange seal closes/seals the bypass ports to prevent fluid
flow in the annular space from below the packer cup to above the
packer cup--e.g. the tool no longer allows annular fluid flow
upward past the sealed packer cup/bypass element). In the second
configuration, fluid may flow from the bore radially outward
through aligned mandrel and radial ports into the annular space,
but the fluid in the annular space is restricted so that it cannot
flow upward beyond the bypass element (which is sealed due to
unaligned annular flow ports and bypass ports (see for example,
FIGS. 4A-4D)).
[0049] By using the two configurations of the tool of FIGS. 1A-B,
fluid flow may be diverted to assist in cutting and removal of
casing from a wellbore. Typically, the tool 100 would be used in a
tool string 102 (as shown in FIG. 2, for example), and the tool
string might comprise a resettable casing spear 175 (operable to be
set and unset by rotation), a motor 174 operable to be powered by
fluid flow through the bore, and a cutter 173 operable to cut the
casing when powered by the motor. Typically, the spear 175 would be
located above the tool 100, and the motor 174 and cutter 173 would
be located below the tool. And in some embodiments, the tool string
would also include magnets (typically located below the tool but
above the cutter). Typically, the spear 175 would be
configured/operable to set when rotated the same direction used to
position the tool 100 in the first configuration (for example,
rotation right in the embodiment of FIG. 1A), and the spear 175
would be configured/operable to unset when rotated the same
direction used to position the tool 100 in the second configuration
(for example, rotation left in the embodiment of FIG. 1B). As FIGS.
3A-7 show, the tool might be used during cutting and extraction of
casing from a wellbore, with rotation of the tool string being used
to switch between configurations to control fluid flow pathways.
These figures will be discussed below in more detail, with regard
to methods/uses of a tool string.
[0050] So, embodiments may also comprise methods of forming up
and/or using a tool in a wellbore (for example to assist in cutting
and pulling casing out of a wellbore). An exemplary method (of
forming and/or operating a tool in a cased wellbore and/or
extracting casing from a wellbore) might comprise one or more of
the following steps: making/forming up a tool string (having a
longitudinal bore therethrough) comprising a rotatable/resettable
spear (e.g. a spear operable to be set or unset based on rotation,
for example with the spear being set by rotation the direction
operable to move/ensure that the tool is in the first
configuration, such as right hand rotation), a cutter (for example,
an expanding-blade cutter operable to cut casing in a wellbore), a
motor (operable to power the cutter, for example a motor operable
to be powered by fluid flow through the tool string (e.g.
longitudinal bore of the tool string)), and a tool for selectively
diverting fluid flow (for example, from the longitudinal bore to
the annular space between the tool and the cased wellbore and/or
allowing or preventing fluid flow upward in the annular space above
the tool, using/having mandrel ports and bypass ports, for example
(such as exemplary FIG. 1A-B)) which has a first position (with
mandrel port(s) closed and bypass port(s) open), and a second
position (with mandrel port(s) open and bypass port(s) closed);
wherein: the tool is operable to be changed from the first
position/configuration to the second position/configuration by
rotation; the spear is typically located above the tool in the tool
string; and the motor and cutter are typically located below the
tool in the tool string. FIG. 2 illustrates such an exemplary tool
string 102. In some embodiments, the method might (further)
comprise running the tool string downhole (in the cased wellbore
185), as shown in FIG. 2 for example; setting the spear by rotation
of the tool string (for example, right hand rotation);
positioning/configuring the tool in the first
position/configuration (as shown in FIGS. 3A-3C, for example, with
mandrel port(s) closed and bypass port(s) open, so that fluid is
operable to flow downward through the bore of the tool string
(exiting the bottom of the tool string, for example, below the
cutter) and then to flow upward to the surface in the annular space
between the tool string and the casing of the cased wellbore--e.g.
circulate the wellbore)) by rotation (e.g. the same rotation as
used to set the spear, for example right hand rotation, with a
single rotation being used to set the spear and position the tool
in the first position); making a cut to the casing of the cased
wellbore (by rotating the tool string in the direction for setting
the spear and positioning the tool in the first
position/configuration (e.g. right hand rotation) while
pumping/circulating fluid down the bore of the tool string (to
power the motor and thereby the cutter) (and up the annular space,
with fluid passing through the bypass port(s) of the tool)); and/or
positioning the tool in the second position (as shown in FIGS.
4A-4D, for example, closing the bypass port(s) and opening the
mandrel port(s)) by rotation (for example, rotation opposite that
used to position the tool in the first position/configuration, e.g.
left hand rotation). Additionally, some embodiments might comprise
overpulling (for example, pulling up on the tool string), typically
after setting the spear and before making a cut.
[0051] In some embodiments, once the cutting is completed, the
method might comprise dropping a ball/plug to seal the longitudinal
bore below the tool and above the motor and cutter (e.g. to seat in
the bore beneath the mandrel ports of the tool and above the cutter
and motor, for example on a shoulder at a narrowed portion of the
bore of the tool string); and flowing fluid through the bore,
through the mandrel port(s) of the tool, down to the cut in the
casing (and hopefully circulating up to the surface on the exterior
of the casing (e.g. between the casing and the wellbore surface)
(e.g. attempting to circulate the well, as shown in FIG. 4D, for
example). If circulation is not possible (all the way up to the
surface), then method embodiments might further comprise unsetting
the spear (e.g. by rotating the spear in the opposite direction
used to set the spear--e.g. rotating left); extracting the ball
from the bore (e.g. by rotating to position the tool in the first
position/configuration (which might be done by the same rotation
used to unset the spear) and reverse pumping/circulating the well
(e.g. pumping fluid down the annular space and up the longitudinal
bore)); repositioning the tool string (longitudinally) in the well
(e.g. pulling the tool string up to reposition the cutter higher in
the well, for example, if previously unable to circulate);
re-setting the spear (for example by rotation--e.g. rotating
right); overpulling the tool string; repositioning/reconfiguring
the tool by rotation to its first position/configuration (for
example, the same rotation used to re-set the spear--e.g. rotating
right) (so that the mandrel port(s) are closed and the bypass
port(s) are open, as shown in FIG. 5, for example); making a
subsequent cut at the new position/location/depth in the well (for
example, by rotating and pumping fluid down the bore, as described
above, while the tool is in the first position/configuration);
repositioning/reconfiguring the tool by rotation (e.g. left
rotation) to its second position/configuration (as shown in FIG. 6,
for example, with mandrel port(s) open and the bypass port(s)
closed); dropping the ball/plug (a second time) to seal the bore
below the tool and above the motor and cutter (e.g. to seat in the
bore beneath the mandrel ports of the tool and above the cutter and
motor, for example on the shoulder at a narrowed portion of the
bore of the tool string); and/or flowing fluid through the bore,
through the mandrel port(s) of the tool, down to the cut in the
casing (and hopefully circulating up to the surface on the exterior
of the casing (e.g. between the casing and the wellbore surface)
(e.g. attempting to circulate the well). This process might be
repeated as many times as necessary in order to circulate to the
surface.
[0052] And once circulation up to the surface has been successfully
accomplished, method embodiments might further comprise the steps
of unsetting the spear (by rotation--e.g. left rotation); pulling
the tool string up (to locate the spear just below the well head);
resetting the spear (by rotation--e.g. right rotation) just below
the well head (e.g. setting the spear at the top of the well, e.g.
just below the well head); and/or extracting the cut casing (e.g.
by pulling the casing upward using the spear, as shown in FIG. 7
for example). This may allow the cut casing (e.g. at least the
uppermost cut segment of casing, for which circulation has been
successful) to be pulled out of the well. And in some embodiments,
one benefit of the method embodiments would be cutting and pulling
the casing in a single trip of the tool string downhole (e.g. there
would be no need to pull the tool string out of the well and/or
re-insert the tool string into the well more than once). Persons of
skill will understand these and other possible benefits regarding
the disclosed embodiments.
[0053] While various embodiments in accordance with the principles
disclosed herein have been shown and described above, modifications
thereof may be made by one skilled in the art without departing
from the spirit and the teachings of the disclosure. The
embodiments described herein are representative only and are not
intended to be limiting. Many variations, combinations, and
modifications are possible and are within the scope of the
disclosure. Alternative embodiments that result from combining,
integrating, and/or omitting features of the embodiment(s) are also
within the scope of the disclosure. And logic flows for methods do
not necessarily require the particular order shown, or sequential
order, to achieve desirable results. Other steps may be provided,
or steps may be eliminated, from the described flows/methods, and
other components may be added to, or removed from, the described
devices/systems. So, other embodiments may be within the scope of
the following claims.
[0054] Accordingly, the scope of protection is not limited by the
description set out above, but is defined by the claims which
follow, that scope including all equivalents of the subject matter
of the claims. In the claims, any designation of a claim as
depending from a range of claims (for example #-##) would indicate
that the claim is a multiple dependent claim based of any claim in
the range (e.g. dependent on claim # or claim ## or any claim
therebetween). Each and every claim is incorporated as further
disclosure into the specification and the claims are embodiment(s)
of the present invention(s). Furthermore, any advantages and
features described above may relate to specific embodiments, but
shall not limit the application of such issued claims to processes
and structures accomplishing any or all of the above advantages or
having any or all of the above features.
[0055] Additionally, the section headings used herein are provided
for consistency with the suggestions under 37 C.F.R. 1.77 or to
otherwise provide organizational cues. These headings shall not
limit or characterize the invention(s) set out in any claims that
may issue from this disclosure. Specifically and by way of example,
although the headings might refer to a "Field," the claims should
not be limited by the language chosen under this heading to
describe the so-called field. Further, a description of a
technology in the "Background" is not to be construed as an
admission that certain technology is prior art to any invention(s)
in this disclosure. Neither is the "Summary" to be considered as a
limiting characterization of the invention(s) set forth in issued
claims. Furthermore, any reference in this disclosure to
"invention" in the singular should not be used to argue that there
is only a single point of novelty in this disclosure. Multiple
inventions may be set forth according to the limitations of the
multiple claims issuing from this disclosure, and such claims
accordingly define the invention(s), and their equivalents, that
are protected thereby. In all instances, the scope of the claims
shall be considered on their own merits in light of this
disclosure, but should not be constrained by the headings set forth
herein.
[0056] Use of broader terms such as comprises, includes, and having
should be understood to provide support for narrower terms such as
consisting of, consisting essentially of, and comprised
substantially of. Use of the term "optionally," "may," "might,"
"possibly," and the like with respect to any element of an
embodiment means that the element is not required, or
alternatively, the element is required, both alternatives being
within the scope of the embodiment(s). Also, references to examples
are merely provided for illustrative purposes, and are not intended
to be exclusive.
[0057] Also, techniques, systems, subsystems, and methods described
and illustrated in the various embodiments as discrete or separate
may be combined or integrated with other systems, modules,
techniques, or methods without departing from the scope of the
present disclosure. Other items shown or discussed as directly
coupled or communicating with each other may be indirectly coupled
or communicating through some interface, device, or intermediate
component, whether electrically, mechanically, or otherwise. Other
examples of changes, substitutions, and alterations are
ascertainable by one skilled in the art and could be made without
departing from the spirit and scope disclosed herein.
* * * * *