Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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INJECTOR AND SLIP BOWL SYSTEM
BACKGROUND
Hydrocarbons, such as oil and gas, are commonly obtained from subterranean
formations that may be located onshore or offshore. The development of
subterranean operations
and the processes involved in removing hydrocarbons from a subterranean
formation are
complex. Typically, subterranean operations involve a number of different
steps such as, for
example, drilling a wellbore at a desired well site, treating the wellbore to
optimize production of
hydrocarbons, and performing the necessary steps to produce and process the
hydrocarbons from
the subterranean formation. Different stages of a subterranean drilling and
completion operation
often involve the use of tubular members, such as coiled tubing, jointed pipe,
or other similar
items.
Coiled tubing, jointed pipe, or other similar tubular members generally
include
cylindrical tubing made of metal or composite. The tubular members may be
introduced into an
oil or gas wellbore or pipeline through wellhead control equipment to perform
various tasks
during the exploration, drilling, production, and workover of the
well/pipeline. For example,
coiled tubing may be inserted by a coiled tubing injector apparatus. Such
injectors generally
incorporate a pair of opposed endless drive chains which are arranged in a
common plane. The
drive chains are often referred to as gripper chains because each chain has
multiple gripper
blocks attached along the chain for handling the tubing as it passes through
the injector.
The opposed gripper chains are provided with a predetermined amount of slack
which allows the gripper chains to be biased against the tubing as the tubing
moves into and out
of the wellbore. This biasing is accomplished with an endless roller chain
disposed inside each
gripper chain. Each roller chain engages sprockets rotatably mounted on a
respective linear
beam. The linear beams may be moved toward one another so that each roller
chain is moved
against its corresponding gripper chain such that the tubing facing portion of
the gripper chain is
moved toward the tubing so that the gripper blocks can engage the tubing and
move it through
the apparatus. When the gripper chains are in motion, the gripper blocks will
engage the tubing
along a working length of the linear beam. Each gripper chain has a gripper
block that comes
into contact with the tubing at the top of the working length of the linear
beam as another gripper
block on the same gripper chain breaks contact with the tubing at the bottom
of the working
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length of the linear beam. This continues as the gripper chains force the
tubing into or out of the
wellbore.
Tubular members introduced into the wellbore may not have a constant cross-
section. For example, a variety of outside diameters of tubing may be used in
a particular
drilling operation, or a pipe joint or connector between two reels of coiled
tubing may result in a
change in outside diameter of the tubular member directed into the wellbore
through the injector.
Existing injector systems that accommodate a range of tubing diameters have a
number of
disadvantages. For example, certain systems utilize two injectors stacked on
top of one another
to allow the injectors to pass an upset (i.e., a change in diameter) that
could not otherwise pass
through either injector with the linear beams closed (i.e., with the gripper
chains engaging the
tubular member). Other injector systems require costly stoppages to make
adjustments and
modifications to the injector and the tubing.
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BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 shows a system including an injector apparatus in accordance with the
present disclosure in position for inserting a tubular member into an adjacent
wellhead.
Figure 2 shows a cross-sectional view of the injector apparatus of Figure 1.
Figure 3 is a flowchart depicting a method for moving a tubular member in and
out
of a well, in accordance with certain embodiments of the present disclosure.
While embodiments of this disclosure have been depicted and described and are
defined by reference to example embodiments, such references do not imply a
limitation on the
disclosure, and no such limitation is to be inferred. The subject matter
disclosed is capable of
considerable modification, alteration, and equivalents in form and function,
as will occur to those
skilled in the pertinent art and having the benefit of this disclosure. The
depicted and described
embodiments of this disclosure are examples only, and not exhaustive of the
scope of the
disclosure.
DETAILED DESCRIPTION OF THE DISCLOSURE
Illustrative embodiments of the present invention are described in detail
herein. In
the interest of clarity, not all features of an actual implementation may be
described in this
specification. It will of course be appreciated that in the development of any
such actual
embodiment, numerous implementation-specific decisions may be made to achieve
the specific
implementation goals, which may vary from one implementation to another.
Moreover, it will
be appreciated that such a development effort might be complex and time-
consuming, but would
nevertheless be a routine undertaking for those of ordinary skill in the art
having the benefit of
the present disclosure.
To facilitate a better understanding of the present invention, the following
examples
of certain embodiments are given. In no way should the following examples be
read to limit, or
define, the scope of the invention. Embodiments of the present disclosure may
be applicable to
horizontal, vertical, deviated, or otherwise nonlinear wellbores in any type
of subterranean
formation. Embodiments may be applicable to injection wells as well as
production wells,
including hydrocarbon wells. Embodiments may further be applicable to borehole
construction
for river crossing tunneling and other such tunneling boreholes for near
surface construction
purposes or borehole u-tube pipelines used for the transportation of fluids
such as hydrocarbons.
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Devices and methods in accordance with embodiments described herein may be
used in one or
more of measurement-while-drilling and logging-while-drilling operations.
The terms "couple" or "couples," as used herein are intended to mean either an
indirect or a direct connection. Thus, if a first device couples to a second
device, that connection
may be through a direct connection or through an indirect mechanical
connection via other
devices and connections. The term "uphole" as used herein means along the
drillstring or the
hole from the distal end towards the surface, and "downhole" as used herein
means along the
drillstring or the hole from the surface towards the distal end.
The present application is directed to methods and systems for performing
subterranean operations and particularly, to methods and systems for moving
tubular members in
and out of a well.
Figure 1 depicts a system including an injector apparatus in accordance with
the
present disclosure, denoted generally with reference numeral 10. The injector
apparatus 10 may
be positioned above a wellhead 12 of a wellbore 13. A lubricator or stuffing
box 16 may be
connected to the upper end of the wellhead 12. A tubular member 18, having a
longitudinal
central axis 25 and an outer surface 23 may be supplied on a large reel or
drum 24. The tubular
member 18 may have any suitable length for the particular application. For
instance, the tubular
member 18 may be several thousand feet in length. Tubular member 18 may be
inserted into the
wellbore 13 as single tubing, tubing spliced by connectors, or tubing spliced
by welding.
The tubular member 18 may have any suitable thickness depending on the
particular
application. For instance, in certain implementations, the ODs of the tubular
member 18 may
range from approximately one inch (2.5 cm) to approximately five inches (12.5
cm). As would
be appreciated by one of ordinary skill in the art, the injector apparatus 10
may be readily
adaptable to larger diameter tubular members. Tubular member 18 may be spooled
from the
drum 24. In certain implementations, the drum 24 may be supported on a truck
(not shown) for
mobile operations.
The injector apparatus 10 may be mounted above the wellhead 12. A guide
framework 28 may extend from the injector apparatus 10. The tubular member 18
may be
supplied from the drum 24 and is run over the guide framework 28. As the
tubular member 18 is
unspooled from the drum 24, it may be directed to pass adjacent to a measuring
device, such as a
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wheel 34. Alternatively, the measuring device may be incorporated into the
injector apparatus
10.
The tubular member 18 may be made from any suitable material known to those of
ordinary skill in the art, having the benefit of the present disclosure. For
instance, in certain
implementations, the tubular member 18 may be made of a material which is
sufficiently flexible
and ductile that it can be curved for storage on the drum 24 and also later
straightened. While the
material may be flexible and ductile and may be capable of bending around a
radius of curvature,
it runs the risk of being pinched or suffering from premature fatigue failure
should the curvature
be severe. In certain embodiments in accordance with the present disclosure,
the tubular
member 18 may comprise a first segment 19, a second segment 20, a third
segment 21, and a
fourth segment 22. The first segment 19 and third segment 21 may have equal
diameters. The
second segment 20 and the fourth segment 22 may have larger outer diameters
("OD") than the
first segment 19 and third segment 21. As would be appreciated by one of
ordinary skill in the
art with the benefit of the present disclosure, the difference in OD between
the first and third
segments 19, 21 and the second and fourth segments 20, 22 may be caused by any
number of
reasons. For example, a pipe joint in straight tubing or a connector
connecting two spools of
coiled tubing may cause a difference in diameters in the tubular member 18.
The disclosed
injector apparatus 10 can be used for injecting, suspending, or extracting any
generally elongated
body without departing from the scope of the present disclosure.
Figure 2 depicts a close-up cross-sectional view of the injector apparatus 10
of
Figure 1. Referring to Figure 2, the details of the injector apparatus
(denoted by reference
numeral 10 in Figure 1) will now be discussed. Injector apparatus (denoted by
reference
numeral 10 in Figure 1) may include a support structure 202. The support
structure 202 may
have a shape and size that is suitable for the particular application. The
support structure 202
may have a number of components including, but not limited to, an i-beam or
plate as the
fabricated structural member. The injector apparatus (denoted by reference
numeral 10 in Figure
1) also may include an injector 204 located at an upper portion thereof, above
the support
structure 202. In certain embodiments, the injector 204 may include a base 206
located
proximate to the support structure 202 and a carriage 208 extending upward
from the base 206
and coupled thereto. In certain implementations, the carriage 208 may be
pivotally attached to
the base 206. In certain embodiments, the injector 204 may further include a
gripper chain
system 210 mounted in the carriage 208. The gripper chain system 210 may
further comprise
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one or more gripper chains 212 and one or more linear beams 214 supporting the
gripper chains
212.
In certain embodiments, gripper chains 212 may engage the tubular member 18
along a working length of the linear beams 214 and a corresponding working
length of the
gripper chain 212. The term "working length," as used herein, refers to the
length of chain or
gripper block that grips and/or uses a compressive force to engage a tubular
member as it moves
though the injector 204. Thus, gripper chain 212 may first contact the tubular
member 18 at an
upper end of the working length of the linear beam 214, and the contact
between the tubular
member 18 and gripper chains 212 may break as the tubular member (denoted by
reference
numeral 18 in Figure 1) passes a lower end of the working length of the linear
beam 214. The
gripper chains 212 may comprise a roller chain 216 and a plurality of gripper
blocks 218.
Gripper blocks 218 may engage the tubular member 18 and may move it through
the injector
204. Any suitable gripper blocks known to those of ordinary skill in the art
may be used without
departing from the scope of the present disclosure. In certain embodiments in
accordance with
the present disclosure, the tubular member 18 may be directed downhole through
the injector
204. As the tubular member 18 is directed downhole through the injector 204,
the gripper blocks
218 may contact an outer surface (denoted by reference numeral 23 in Figure 1)
of the tubular
member 18 along the longitudinal central axis (denoted by reference numeral 25
in Figure 1)
thereof.
In certain embodiments, the injector 204 may also comprise one or more
sprockets
(not shown) to drive the gripper chain 212 and a mechanical device (not shown)
to provide
motive force. The mechanical device may be a hydraulic or electric motor. The
injector 204
may also include an actuator (not shown) that may be used to move the linear
beams 214 towards
and away from the tubular member 18.
The injector apparatus (denoted by reference numeral 10 in Figure 1) also may
include a lifting means 220 for moving the injector 204 vertically with
respect to the base 206.
In certain implementations, the lifting means 220 may include, but is not
limited to, a set of
hydraulic cylinders 220A and 220B. Each of the hydraulic cylinders 220A, 220B
may be
coupled to the injector 204 and the support structure 202. The hydraulic
cylinders 220A, 220B
may be operable to move the injector 204. The hydraulic cylinders 220A, 220B
may apply
external force to lift the injector 204 vertically with respect to the base
202. As would be
appreciated by one of ordinary skill in the art with the benefit of the
present disclosure, the
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hydraulic cylinders 220A, 220B may include one or more cylinder rods (not
shown). While two
hydraulic cylinders are depicted in the example of Figure 2, it should be
understood that any
suitable number of hydraulic cylinders may be utilized. Furthermore, as would
be appreciated
by those of ordinary skill in the art, with the benefit of this disclosure,
the example of hydraulic
cylinders should not be seen as limiting. Specifically, alternative lifting
means of applying
external force to lift the injector 204 may be utilized without departing from
the scope of the
present disclosure. Such alternative means may include, but are not limited
to, electric actuators,
chain actuators, and draw works.
The injector apparatus (denoted by reference numeral 10 in Figure 1) also may
include a slip bowl assembly 222 coupled to the support structure 202. The
slip bowl assembly
222 may be located below the injector base 206. The slip bowl assembly 222 may
engage and
release the tubular member 18 along its longitudinal central axis (denoted by
reference numeral
25 in Figure 1). The slip bowl assembly 222 may include any suitable slip
bowl, including one
or more conventional slip bowls, operable to engage or release the tubular
member 18 and
adapted for the load transfer features described herein. Each slip bowl
assembly 222 may be
configured to engage tubular member 18 with a bite biased along the
longitudinal central axis 25.
In certain implementations, the slip bowl assembly 222 may be moveably coupled
to the support
structure 202. The slip bowl assembly 222 may also be oriented in a position
that is inverted
from that shown in Figure 1. Furthermore, more than one slip bowl assembly 222
may be used
in this embodiment, wherein the two bowls are oriented in opposition to one
another. The slip
bowl assembly 222 may be oriented in any suitable manner without departing
from the scope of
the present disclosure.
Operation of the injector apparatus (denoted by reference numeral 10 in Figure
1) in
accordance with an illustrative embodiment of the present disclosure will now
be discussed in
conjunction with Figures 2 and 3. Figure 3 is a flowchart depicting
illustrative method steps
associated with a method for moving a tubular member in and out of a well, in
accordance with
an illustrative embodiment of the present disclosure. Although a number of
steps are depicted in
Figure 3, as would be appreciated by those of ordinary skill in the art,
having the benefit of the
present disclosure, additional steps may be implemented or one or more of the
recited steps may
be eliminated or modified without departing from the scope of the present
disclosure.
First, at step 302, tubular member 18 is directed downhole through the
injector 204.
The gripper chains 212 and gripper blocks 218 engage the first segment
(denoted by reference
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numeral 19 in Figure 1) of the tubular member 18 until the gripper blocks 218
of the injector 204
encounter the second segment (denoted by reference numeral 20 in Figure 1) of
the tubular
member 18. At step 304, after the injector 204 encounters the second segment
(denoted by
reference numeral 20 in Figure 1), the slip bowl assembly 222 engages the
first segment
(denoted by reference numeral 19 in Figure 1) of the tubular member 18.
Specifically, the slip
bowl assembly 222 imparts at least a minimum threshold of compressive force on
a portion of
the tubular member 18 and may substantially prevent the tubular member 18 from
moving
upward and/or downward along the longitudinal central axis (denoted by
reference numeral 25 in
Figure 1) of the tubular member 18. At this step, the first segment (denoted
by reference
numeral 19 in Figure 1) of the tubular member 18 may be engaged by the slips
(not shown) of
the slip bowl assembly 222 and is under compression.
Next, at step 306, the linear beams 214 of the injector 204 are moved away
from one
another, causing the gripper chains 212 and gripper blocks 218 to disengage
the tubular member
18. At step 308, the lifting means 220 is actuated to move the injector 204
vertically with
respect to the base 202 until the injector 204 is positioned above the second
segment (denoted by
reference numeral 20 in Figure 1) of the tubular member 18, thus bypassing an
upset in the
tubular member 18. At step 310, the linear beams 214 of the injector 204 are
moved toward one
another, causing the gripper chains 212 and gripper blocks 218 to engage the
third segment
(denoted by reference numeral 21 in Figure 1) of the tubular member 18. Next,
at step 312, the
slip bowl assembly 222 releases the first segment (denoted by reference
numeral 19 in Figure 1)
of the tubular member 18, allowing the tubular member 18 to once again move
upward and/or
downward along a longitudinal central axis (denoted by reference numeral 25 in
Figure 1) of the
tubular member 18. Finally, at step 314, the tubular member 18 continues to be
directed
downhole through the injector 204 until the injector 204 encounters the fourth
segment (denoted
by reference numeral 22 in Figure 1) of the tubular member 18. Once the
injector 204
encounters the fourth segment (denoted by reference numeral 22 in Figure 1),
the fourth segment
(denoted by reference numeral 22 in Figure 1) of the tubular member 18 is
engaged by the slips
(not shown) of the slip bowl assembly 222 and is under compression, as
discussed above with
respect to step 304. As would be appreciated by those of ordinary skill in the
art, with the
benefit of this disclosure, steps 304 through 314 may be repeated multiple
times without
departing from the scope of this disclosure.
Referring back to Figure 1, in certain embodiments in accordance with the
present
disclosures, the tubular member 18 (i.e., tools, tool joints, etc.) can be
disassembled,
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disconnected, and/or removed, or additional tools may be added, below the
injector apparatus 10
in order to install or remove a tubular member that is not able to pass
through the injector
apparatus 10 in the opened position. This may be performed one or more times
during the
course of a single job. This operation is well known to those of ordinary
skill in the art having
the benefit of the present disclosure and will therefore, not be discussed in
detail herein.
In accordance with certain embodiments of the present disclosure, during
normal
operations, the injector apparatus 10 may be used to pass an upset that could
not otherwise pass
through a prior art injector. In certain embodiments, the second segment 20 of
the tubular
member 18 may have a larger diameter than the first segment 19 and third
segment 21 of the
tubular member 18. Accordingly, the injector apparatus 10 disclosed herein may
be particularly
beneficial in instances where tubular members having different size diameters
are utilized or in
situations where a single, connected tubular member has differing diameters.
Further, utilizing a
slip bowl assembly and a lifting means, as described herein, provides a method
of using only one
injector to accommodate tubular members of various sizes.
In certain implementations, the injector apparatus 10 in accordance with the
present
disclosure may provide safety advantages over prior art injectors. For
example, one particular
type of prior aft injector apparatus utilizes two injectors stacked on top of
one another. The
stacked or dual injector system would use two injectors, only one of which
would be closed at a
given time. This type of dual injector system allows for a change of ODs
(e.g., different tools,
tool joints, etc.) to be run into the wellbore. However, stacked or dual
injector systems may have
many disadvantages, including, but not limited to, heavier, taller rig ups,
extended rig up time,
operational complexity, higher capital cost, and higher maintenance cost. In
contrast, an injector
apparatus 10 in accordance with the present disclosure reduces rig time,
costs, and operational
complexity. Specifically, the injector apparatus 10 disclosed herein may
provide for significant
cost savings because the slip bowl assembly may cost as little as less than
one tenth the cost of a
second injector.
Accordingly, an improved injector apparatus is disclosed which may accommodate
tubular members of differing diameters. The slip bowl assembly 222 of Figure 2
engages the
tubular member 18 when a second segment 20 is encountered and the injector 204
of Figure 2 is
lifted above the second segment 20 in order to avoid the upset. In this
manner, the improved
injector apparatus 10 disclosed herein may conform rapidly to changing
geometries of tubing to
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reduce the number of stoppages for adjustments and modifications required in
prior art tubing
injector apparatuses.
Although the figures depict embodiments of the present disclosure in a
particular
orientation, it should be understood by those skilled in the art that
embodiments of the present
disclosure are well suited for use in a variety of orientations. Further, it
should be understood by
those skilled in the art that the use of directional terms such as up, down,
above, below, upper,
lower, upward, downward and the like are used in relation to the illustrative
embodiments as
they are depicted in the figures, the upward direction being toward the top of
the corresponding
figure and the downward direction being toward the bottom of the corresponding
figure.
An embodiment of the present disclosure is an injector apparatus for moving a
tubular member in and out of a well. The injector apparatus includes a support
structure and an
injector located above the support structure. The injector includes a base, a
carriage extending
upward from the base and coupled to the base, and a gripper chain system
mounted in the
carriage. The gripper chain system includes one or more gripper chains and one
or more linear
beams supporting the one or more gripper chains. The injector apparatus
further includes one or
more hydraulic cylinders coupled to the support structure, wherein the one or
more hydraulic
cylinders are operable to move the injector. The injector apparatus further
includes a slip bowl
assembly coupled to the support structure and located below the injector base.
Optionally, the one or more hydraulic cylinders include two hydraulic
cylinders.
Optionally, the one or more hydraulic cylinders are coupled to the injector.
Optionally, the slip
bowl assembly includes one or more slip bowls. Optionally, the gripper chains
include a roller
chain and a plurality of gripper blocks.
Another embodiment of the present disclosure is an injector and slip bowl
system for
moving a tubular member in and out of a well. The system includes an injector
apparatus. The
injector apparatus includes a support structure and an injector located above
the support
structure. The injector includes a base, a carriage extending upward from the
base and coupled
to the base, and a gripper chain system mounted in the carriage. The gripper
chain system
includes one or more gripper chains and one or more linear beams supporting
the one or more
gripper chains. The injector apparatus further includes a lifting means
coupled to the support
structure and a slip bowl assembly coupled to the support structure and
located below the base.
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Optionally, the lifting means is selected from a group consisting of one or
more
hydraulic cylinders, an electric actuator, a chain actuator, and draw works.
Optionally, the
gripper chains include a roller chain and a plurality of gripper blocks.
Optionally, the slip bowl
assembly includes one or more slip bowls. Optionally, the gripper chains
engage and release the
tubular member along a longitudinal central axis of the tubular member.
Optionally, the gripper
blocks engage and release the tubular member along a longitudinal central axis
of the tubular
member. Optionally, the slip bowl assembly engages and releases the tubular
member along a
longitudinal central axis of the tubular member. Optionally, the tubular
member is directed
downhole through the injector.
Another embodiment of the present disclosure is a method for moving a tubular
member in and out of a well. The method includes directing the tubular member
downhole
through an injector. The tubular member includes a first segment, a second
segment, and a third
segment, and the second segment has a larger diameter than the first segment
and third segment.
The injector comprises a base, a carriage extending upward from the base and
coupled to the
base, a gripper chain system mounted in the carriage and including one or more
gripper chains
and one or more linear beams supporting the one or more gripper chains, a
lifting means coupled
to the support structure, and a slip bowl assembly coupled to the support
structure and located
below the base. The gripper chains engage the first segment of the tubular
member until the
injector encounters the second segment. The method further includes engaging
the slip bowl
assembly, wherein the slip bowl assembly imparts a compressive force on the
first segment of
the tubular member. The method further includes moving the linear beams of the
injector away
from one another, wherein the movement of the linear beams disengages the
tubular member
from the gripper chains. The method further includes actuating the lifting
means to move the
injector vertically with respect to a base of the injector until the injector
is positioned above the
second segment of the tubular member. The method further includes moving the
one or more
linear beams of the injector toward one another, wherein the movement of the
linear beams
causes the gripper chains to engage the third segment of the tubular member.
Finally, the
method includes disengaging the slip bowl assembly from the first segment of
the tubular
member.
Optionally, the lifting means is selected from a group consisting of one or
more
hydraulic cylinders, an electric actuator, a chain actuator, and draw works.
Optionally, the first
segment and the third segment have equal diameters. Optionally, the gripper
chains include a
roller chain and a plurality of gripper blocks. Optionally, the gripper blocks
of the gripper chains
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engage the tubular member. Optionally, the tubular member further includes a
fourth segment
with a diameter greater than the first or third segments, and the method
further includes the step
of directing the tubular member downhole through an injector until the
injector encounters the
fourth segment of the tubular member. Optionally, the tubular member is
disassembled below
the injector apparatus.
The present invention is therefore well-adapted to carry out the objects and
attain the
ends mentioned, as well as those that are inherent therein. While the
invention has been
depicted, described and is defined by references to examples of the invention,
such a reference
does not imply a limitation on the invention, and no such limitation is to be
inferred. The
invention is capable of considerable modification, alteration and equivalents
in form and
function, as will occur to those ordinarily skilled in the art having the
benefit of this disclosure.
The depicted and described examples are not exhaustive of the invention.
Consequently, the
invention is intended to be limited only by the spirit and scope of the
appended claims, giving
full cognizance to equivalents in all respects.
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