Note: Descriptions are shown in the official language in which they were submitted.
CA 02610203 2007-11-13
STRESS REDUCED CEMENT SHOE OR COLLAR BODY
BACKGROUND OF THE INVENTION
Field of the Invention
Embodiments disclosed herein generally relate to an apparatus and
method of making and/or using a downhole shoe and/or collar. More
particularly,
the embodiments disclosed herein relate to shoe and collars for use in
downhole
cementing operations. More particularly still, the embodiments disclosed
herein
relate to float shoes and collars configured with an internal radiused profile
configured to reduce leaking around the valve and through the body of the
float
shoe and float collar, while increasing the compression capability of the
apparatus.
Description of the Related Art
In the drilling of oil and gas wells, a wellbore is formed using a drill bit
that is urged downwardly at a lower end of a drill string. After drilling a
predetermined depth, the drill string and bit are removed and the wellbore is
lined
with a string of casing. An annular area is thus formed between the string of
casing and the wellbore. A cementing operation is then conducted in order to
fill
the annular area with cement. The combination of cement and casing strengthens
the wellbore and facilitates the isolation of certain areas of the formation
behind
the casing for the production of hydrocarbons.
It is common to employ more than one string of casing in a wellbore. In
this respect, a first string of casing is set in the wellbore when the well is
drilled to
a first designated depth. The first string of casing is hung from the surface,
and
then cement is circulated into the annulus behind the casing. The well is then
drilled to a second designated depth, and a second string of casing or liner
is run
into the well. The second string of casing or liner is also cemented. This
process
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CA 02610203 2007-11-13
is typically repeated with additional casings or liners until the well has
been drilled
to total depth.
In a conventional cementing operation a float shoe is attached to the
bottom of the casing string as the casing string is run into the wellbore. The
float
shoe typically has a one-way valve located within the shoe. The casing is run
into
the wellbore to the desired depth and a cementing operation is performed. The
cementing operation commences with a first plug being dropped into the casing.
The first plug typically has a through bore with a rupture disk therein.
Behind the
plug, cement is pumped into the casing. Following the cement, a second
typically
solid plug is dropped into the casing. The first plug lands on the float shoe.
As the
pressure of the cement behind the first plug increases, the ruptured disk
fails. The
cement flows through the bore of the first plug and past the one-way valve in
the
float shoe until the second plug reaches the first plug. The one-way valve
allows
the cement to flow out of the float shoe and into the annulus between the
casing
and a wellbore therearound while preventing the cement from reentering the
casing string.
The float shoe typically comprises a collar 100 with angular wickers 102
formed on the internal diameter of the collar 100, as shown in Figure 1. A
wicker
is a circumferential groove that is not typically helical in the interior of
the float
shoe. The upper end of the collar 100 couples to the casing. The interior of
the
collar 100 includes a one-way valve 106, which is held in place by a cured
cement
108. The lower end of the float shoe has a rounded nose 110 formed of the
cured
cement 108. A bore 112 is created in the cured cement 108 to allow the
cementing operation cement to flow past the one way valve 106 and the float
shoe. The angular wickers 102 provide an irregular surface which enables the
cured cement to be adequately retained with the collar 100. The angular
wickers
102 place a compressive stress on the cured cement when the shoe is loaded
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from either end. The angular wickers 102 include a downward facing shoulder
114, a flat wall 115, and an upward facing shoulder 116.
As the float shoe is run into the wellbore, back pressure is applied to the
float shoe. Back pressure is pressure on the down hole side of the float
valve.
Back pressure may be created in various ways. A dynamic back pressure is
created during the run in of the float shoe. The dynamic back pressure is
simply
the resistance of the wellbore fluids on the float shoe as it is lowered into
the
wellbore. A static back pressure may be created due to wellbore fluids in the
annulus 203 having a greater pressure than fluid inside the float shoe and
casing.
The back pressure may be created during testing of the float shoe, either
downhole or before running into the wellbore. Further, the nose may encounter
objects on the bottom of the wellbore as it is run in. The back pressure
and/or the
weight of the casing will place stress on the cured cement 108. The plugs used
during the cement operation will impact the float shoe and thereby place a
bump
pressure on the top side of the float shoe. The bump pressure places the
concrete
into compression between the uphole side of the float shoe and the upward
facing
shoulders 116 as the pressure behind the plugs increases.
In the float shoe, stress risers occur at angles O and 0 of the angular
wickers 102, as shown in Figure 1A. As back pressure, bump pressure, or both
are placed on the float shoe, the cement 108 is placed in compression. The
compression is distributed over the float shoe as a pressure. The pressure
applies
a force F to the angled wickers 102 in a direction normal to each surface,
downward facing shoulder 114, a flat wall 115, and an upward facing shoulder
116
of the angular wicker 102. The force F applied to the surfaces 114, 115, and
116
of the angled wickers 102 create stress risers 122 at angles O and 0. These
stress risers 122 are increased areas of stress in the cement 108. The stress
risers 122 locally place the cement 108 in tension in some instances. The high
tensile stress in the cement 108 at the stress riser 122 causes failure of the
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cement 108. That failure may cause leak paths to form along the interior of
the
sleeve. Further, the back pressure or the bump pressure may cause a shear
stress between the cured cement 108 in the angular wickers 102 and the cured
cement 108 outside of the angular wickers 102. The shear stress causes further
failing of the cement and the float shoe.
The traditional float shoes, as shown in Figure 1, have small leak paths
along the angular wickers 102 that form due to shrinkage of the cured cement
108.
Back pressure and/or bump pressure can crack or further crack the cured cement
along the stress riser paths 122 formed by the angular wickers 102, thereby
creating or exacerbating leakage along leak paths. The stresses on the rounded
noses 110 of the float shoe create a failure of the nose at a location 120.
The
failure in the rounded nose 110 causes the nose to fall off at relatively low
back
pressures. With the rounded nose 110 off, the stress in the remaining cured
cement 108 is enhanced and the leak paths allow increased volumes of fluids to
flow past the float shoe.
The angles 0 and 0 on the float shoe require the angular wickers to be
machined from two axial directions. For example, when machining from the
rounded nose 110 end of the collar 100, it is only possible to cut angles O
and 0
of the downward facing shoulder 114. Thus, the collar 100 is placed on the
lathe
and machined in a first axial direction to cut one of the shoulders 114 or
116. The
collar is then placed on the lathe and the same process is repeated from a
second
axial direction. The angles 0 and 0 of the angular wickers 102, in reality,
have a
small radius. This small radius is caused by machining limitations. More
precise
cutting tools will reduce the small radius; however, the small radius is
always less
than 1/32". It is known to use float shoes or float collars that only require
cutting in
one direction. However, these float shoes or float collars have only one sharp
angled shoulder 114 or 116. Therefore, these float shoes or float collars hold
high
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pressure in only one axial direction. That is the float shoes or float collars
are only
capable of holding back pressure or bump pressure but not both.
Therefore a need exists for float shoes or float collars capable of holding
bi-directional pressure. There is a further need for a float valve having an
increased resistance to leaking and failure. There is a further need of float
shoes
or float collars that can be manufactured with a one pass machining operation.
SUMMARY OF THE INVENTION
Embodiments described herein relate to a cementing assembly. The
cementing assembly has a sleeve having an internal profiled portion. The
internal
profiled portion includes a first radiused portion culminating in a first
minimum
radius toward an exterior of the sleeve and a second radiused portion
culminating
in a second minimum radius toward an interior of the sleeve. The cementing
assembly further includes a bore located in the interior or the sleeve and a
compound for coupling the valve to the sleeve wherein the first minimum radius
and the second minimum radius are configured to reduce stress risers in the
compound.
BRIEF DESCRIPTION OF THE DRAWINGS
So that the manner in which the above recited features of the present
invention can be understood in detail, a more particular description of the
invention, briefly summarized above, may be had by reference to embodiments,
some of which are illustrated in the appended drawings. It is to be noted,
however, that the appended drawings illustrate only typical embodiments of
this
invention and are therefore not to be considered limiting of its scope, for
the
invention may admit to other equally effective embodiments.
Figure 1 is a cross-sectional view of a float shoe.
Figure 1A is a view of one angular wicker.
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Figure 2 is a cross sectional view of a wellbore according to one
embodiment described herein.
Figure 3 is a cross-sectional view of a float shoe according to one
embodiment described herein.
Figure 4 is a view of the inner profiled portion according to one
embodiment described herein.
Figure 5 is a cross-sectional view of a float collar according to one
embodiment described herein.
Figure 6 is a cross-sectional view of a component according to one
embodiment described herein.
Figure 7 is a cross-sectional view of a wellbore.
DETAILED DESCRIPTION
Figure 2 shows a cross sectional view of a wellbore 200 according to
one embodiment described herein. The wellbore 200 has a tubular 202 which is
being run into and set in the wellbore 200. Between the wellbore 200 and the
tubular 202 is an annulus 203. The tubular 202, as shown, is a casing;
however, it
could be any wellbore tubular such as a liner, a drill string, a production
tubing, a
coiled tubing, etc. The tubular 202 is run into the wellbore 200 to a desired
location. A cementing operation is then performed in order to fix the tubular
202 in
place and isolate production zones, not shown, located within the wellbore
200.
The tubular 202 is coupled at its lower end to a valve assembly 204, shown
schematically. The valve assembly 204 has a valve 206, a bore 208, a sleeve
210, and a compound 212. The valve assembly 204, as shown, is a float shoe;
however, it is contemplated that a float collar or any other cementing
assembly
may be used. The valve 206 is shown and described as a one-way valve or check
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valve; however, other valves may be used such as a flapper valve, a gate
valve, a
pop-off valve, or that no valve is used. Further, although shown as having one
valve 206, any number of valves may be used in order to increase reliability
of the
valve assembly. The sleeve 210 includes a radiused inner profile, discussed in
more detail below, configured to reduce stresses in the compound 212 while
retaining the compound 212 in the sleeve 210.
The cementing operation is performed by dropping a first plug 214,
shown schematically, into the interior bore of the tubular 202. The first plug
214 is
followed by a cement 216 for cementing the annulus 203 and a second plug 218,
shown schematically. The second plug 218 is pushed down hole by a pumping
fluid, not shown. The pumping fluid may be any fluid capable of pushing the
second plug 218 through the tubular 202, such as drilling mud, water, etc. The
first plug 214 travels down the tubular until it lands on the valve assembly
204.
With the first plug 214 engaged with the valve assembly 204, a bump pressure
is
created between the first plug 214 and the valve assembly 204. As the pumping
fluid pressure increases behind the second plug 218, the pressure increases in
the
cement 216 thereby increasing bump pressure on the valve assembly 204. The
bump pressure increases until a rupture disk (not shown) bursts on the first
plug
214. With the rupture disk burst, the cement 216 flows through the first plug
214
into the bore 208 to the valve 206. Initially when the rupture disk bursts, a
portion
of the bump pressure is relieved from the top of the valve assembly 204. The
fluid
pressure of the cement may then open the valve 206 or the valve may be
remotely
opened depending on the valve. The cement 216 then flows past the valve
assembly 204 and into the annulus 203. The cement 216 continues to flow out
into the annulus 203 until the second plug 218 lands on the first plug 214.
With
the second plug 218 on the first plug 214, continued pressuring of the pumping
fluid increases the bump pressure on the valve assembly 204. The valve 206 may
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then close in order to prevent the cement 216 from flowing back into the
tubular
202 or U-tubing.
The cement 216 is allowed to cure in the annulus 203. A milling or
drilling tool then lowers into the tubular 202 in order to mill out the second
plug
218, the first plug 214, and the valve assembly 204. If necessary, the
wellbore
200 may be drilled lower and any number of additional tubulars 202 placed into
the
wellbore 200 in the same manner as described above.
Figure 3 shows a cross sectional view of the valve assembly 204,
according to one embodiment described herein. The valve assembly 204 includes
the sleeve 305, the valve 206, a compound 300 for holding the valve 206 in the
sleeve 210, and the bore 208 formed in the compound 300. In one embodiment,
the compound 300 is cement; however, the compound could be a composite, an
impregnated cement, a polymer, or any suitable compound, preferably a castable
compound. The compound forms a nose 301 at the lead end and a seat 302 at
the up-hole end of the valve assembly 204. The valve 206, as shown, is a one-
way valve having a body 303, a plunger 304, and a biasing member 306 for
biasing the plunger 304 toward the closed position. The biasing member 306 is
shown as a coiled spring; however, it should be appreciated that the biasing
member may be any member capable of biasing the valve 206 toward the closed
position, such as a resilient member, a leaf spring, a fluid bias, etc.
The sleeve 305 has a connector end 307, an internally profiled portion
308, and a lead end 312. The connector end 307 is shown as a box end of a
threaded connection for coupling the valve assembly 204 to the tubular 202;
however, it is contemplated that the connector end 307 be any type of
connection
for use in a downhole setting, such as a pin end, a welded connection, etc.
The
internally profiled portion 308, as shown, has a plurality of radiused
portions which
have a series of hills 314 and valleys 316. The hill 314 is any part of the
internal
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CA 02610203 2007-11-13
profiled portion 308 which culminates toward the interior of the sleeve 305.
The
valley 316 is any part of the internal profiled portion which culminates
toward the
exterior of the sleeve 305. Figure 4 shows a view of one segment of the
internally
profiled portion 308. The distance between the hills 314 is shown as X. The
hill
314 has a radius R1. The distance between the peak of the hill 314 and the
valley
316 is shown as the depth D. The depth D is typically greater than 0.08
inches.
Typically the depth D is 0.125 inches, 0.15 inches, or 0.2 inches; however it
should
be appreciated that the depth D may be any depth desired. The valley 316 has a
radius R2. The radii R1 and R2 are the minimum radius of the hill 314 and the
valley 316 on the internally profiled portion 308. In the embodiment shown in
Figure 3, the ratio of R1 to R2 is 2:1 and the distance X is 2 inches. One
advantage to design herein disclosed is to create an undulated surface with no
abrupt changes from one radius to the next.
The internal profiled portion 308 is designed to be manufactured with
one pass of a cutting tool, not shown. The cutting tool passes through the
sleeve
305 as the sleeve is rotated on a lathe. The cutting tool cuts away the
valleys 316
of the internal profiled portion 308. By cutting the valleys 316, the hills
314 are
formed at the peaks of the valleys 316. Due to the gradual change in the
radius of
the valleys 316 and the hills 314, the forming of the hills 314 and valleys
316 does
not require the cutting tool to cut the sleeve in two axial directions. Thus,
the
sleeve 305 may be placed on a lathe and the cutting tool may enter the sleeve
from either the nose end or the connector end of the sleeve 305 and cut the
internal profiled portion 308 in one pass and/or in one cutting direction.
Therefore,
the manufacturing time is greatly decreased from traditional angular wickers,
which require the milling tool to cut in both directions in order to form the
wickers.
Alternatively, the sleeve 305 may be manufactured by hydroforming, roll
forming,
or any other suitable technique.
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In operation, the valve assembly 204 is coupled to the lower end of the
tubular 202, as shown in Figure 2. The valve assembly 204 and tubular 202 are
then lowered into the wellbore 200 by a rig until they reach a desired depth.
A
back pressure may be present on the valve assembly 204 during run-in. The back
pressure creates a force on the nose 301. The back pressure may also create a
force on the interior of the valve 206 in addition to the force on the nose
301. The
force on the nose 301 and the valve assembly 204 immediately places the
compound 300 located in the valleys 316 into compression. The compression in
the valleys 316 helps seal the interior of the sleeve 305, thereby preventing
fluids
from leaking past the valve assembly 204.
The back pressure may remain on the valve assembly 204 until and/or
during and after the cementing operation. The first plug 214 drops into the
tubular
202 to commence the cementing operation. The first plug 214 is followed by the
cement 216 and the second plug 218. The first plug 214 creates the bump
pressure on the seat 302 upon engagement. The bump pressure places the
compound 300 in compression. The first plug 214 increases the bump pressure
on the seat 302 until the rupture disk of the first plug 214 is set off. The
cement
216 in front of the second plug 218 enters the bore 208 and puts pressure on
the
up hole side of the plunger 304. The pressure on the up hole side of the
plunger
304 is increased by increasing the pumping pressure behind the second plug
218.
The up hole pressure on the plunger 304 will continue to rise until the force
on the
up hole side of the plunger 304 is greater than the force of the biasing
member
306 and the force created by any back pressure. The up hole pressure then
moves the plunger 304 to create a flow path for the cement to flow past the
valve
206. The pumping fluid continues to push the second plug 216 down until the
second plug reaches the first plug 214. With the second plug 216 on top of the
first plug, the cement 216 is in the annulus 203. The pumping pressure may be
relieved from the second plug 316. The up hole pressure on the plunger 304
CA 02610203 2007-11-13
decreases until the biasing member 306 overcomes the pressure and closes the
valve 206. The valve 206 prevents the cement 216 from reentering the tubular
202. The cement is allowed to cure. The first plug 214, the second plug 216,
the
compound 300, and the valve 206 may then be drilled or milled out to allow
access
to locations below the valve assembly 204. The entire process may be repeated
as needed.
The stresses created in the compound 300 due to back pressure and
bump pressure are greatly reduced due to the radiused internal profiled
portion
308. The gradually changing angles of the hills 314 and the valleys 316
prevent
large stress risers from occurring in the internal profiled portion 308. The
radiused
profiles further provide a larger load bearing surface area than traditional
angular
wickers. The larger surface area reduces the stresses created by the bump
pressure and the back pressure. Because the stress risers and stresses are
reduced in the compound 300, the valve assembly 204 is capable of higher
loading than the traditional angular wicker float shoes. Therefore, the
geometry of
the internal profiled portion 308 prevents the nose 301 from failing while
back
pressure is applied to the valve assembly 204. For example, the typical prior
art
float shoe nose fails and breaks at about 4,000 psi of back pressure. The nose
301 of the valve assembly 204 described herein has been tested at 10,000 psi
of
back pressure without failing, cracking, or leaking.
Figure 5 depicts an alternative embodiment of the valve assembly 204.
A float collar 500 has an internal profile portion 508 similar to that of the
internal
profile portion 308. The float collar 500 includes a valve 504 having a
plunger 505
and a biasing member 506. The valve 504 is secured in the interior of the
float
collar 500 with a compound 507. The compound 507 is similar to the compound
300 discussed above. The float collar 500 further includes a spacer 510,
optional,
which provides additional space for a bore 512. The spacer 510 may be any
length and allows the float collar 500 to be manufactured with a longer
internal
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profiled portion 508. The spacer 510 is shown having a radiused exterior
similar to
the internal profiled portion 508; however, it should be appreciated that the
exterior
of the spacer 510 may have any configuration. The spacer 510 may be
incorporated into any of the embodiments described herein. The internal
profiled
portion 508 includes one or more hills 514 and one or more valleys 516 which
operate in the same manner as described above. The hills 514 and valleys 516
are radiused as described above. The float collar 500 has an up hole connector
509 and a downhole connector 518. As shown, the up hole connector 508 is a
threaded box connection and the downhole connector 518 is a threaded pin end.
The downhole connector may be connected to a bottom hole assembly (BHA),
tools, or a second tubular, not shown. The float collar operates in the same
manner as the valve assembly 204.
Although the radius R1 and R2 are described above as having a 2:1
ratio respectively, it is contemplated that the R1 and R2 are substantially
equal. In
an alternative embodiment R2 may be larger than R1. Further, the radius of
each
hill 314/514 and each valley 316/516 of the internal profiled portion 308/ 508
may
vary from one hill or valley to the next hill and valley. The minimum length
of R1
and R2 required to prevent high stress risers from forming the compound 300
and
507 is greater than 1/32 inches.
In yet another embodiment, the tangent point between the Radii R1 and
R2 is approximately 1/3 of the depth D from the hill 316. That is, the radius
R1
bends into R2 at a location which is approximately 1/3 of the depth D from the
hill
316. The second radius R2 of the valley 314, in this configuration, is where
most
of the cement is in compressive contact with the internal profiled portion
308/508
when loading.
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CA 02610203 2007-11-13
In an alternative embodiment, the internal profiled portion 308/508 is
one or more spiraled or helical grooves, as opposed to circumferential
grooves,
that extend along the interior or the valve assembly 204.
In an alternative embodiment, the internal profiled portion 308/508 is a
plurality of separate dimples which may extend circumferentially and/or
axially in
the tubular. The interaction between the dimples and the compound 212 would be
similar to that of the internal profiled portion 308/508 and the compound 212.
In an alternative embodiment, the internal profile may have irregular
radii R1 and R1 and have varying dimensions X and D. Further, the radiused
portions may be intermittent and/or spaced apart from one another. These
examples are not meant to limit the internal profile to these geometries.
In the above embodiments the internal profile has been described in
conjunction with the valve assembly 204; however, it should be appreciated
that
other components may be used in addition to or as an alternative to the valve
assembly 204. In Figure 6 a component 600 held in a tubular 602 by the
compound 212 which engages the component and the internally profiled portion
308, as described above. The tubular 602, as shown, may be a joint or a full
string
of casing or production tubing; or, may relatively short tubular or a collar
which is
within a longer tubular string. The tubular 602 includes the internally
profiled
portion 308 which acts to reduce the force in the compound during operation of
the
component 600. In addition or alternative to the internally profiled portion
308, a
component profile 604 and/or an outer tubular profile 606 accompany the
component 600 and/or the tubular 602. The component profile 604 and the outer
tubular profile 606 may have any of the shapes described herein. The component
profile 604 serves to reduce stresses in the compound 212 in the same manner
as
described above. As shown in Figure 6, the component 600 is a location profile
in
the tubular 602. The location profile is adapted to engage a tool that is
dropped or
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pumped into the tubular 602. The location profile may be adapted to catch
and/or
seat any suitable downhole tool including, but not limited to, a dart, a ball,
a
downhole pump, another tubular string, a packer for example a swell packer or
an
inflatable packer, an expansion tool, pump down floats, expandable casing, or
a
whipstock.
The outer tubular profile 606 may be used in conjunction with the inner
profiles 308 and component 600, or may be used independent of inner profile
308
and the component 600. Any tubular 602 in which a compound is applied to the
outer diameter of the tubular 602 may include the outer tubular profile 606.
For
example, the tubular 602 may be a casing run into a wellbore. The casing may
have one or more outer tubular profile 606 portions along the entire length of
the
casing.
When the casing 702 is cemented into a wellbore 700, as shown in
Figure 7, the cement 704 is pumped into an annular space between the exterior
of
the casing and the wall of the borehole, where it hardens. The profile
portions 606
enable the cement to achieve a robust bond to the casing. This is advantageous
in promoting a seal, eliminating problems with micro-annuli between casing and
cement. Additionally, this enables the casing to be supported against axial
loading. For example, during the life of the well, the casing may be subjected
to
temperature cycling caused by periods of production or injection punctuated by
periods in which the well is closed-in. The casing would therefore be
subjected to
axial stress cycles due to thermally-induced expansion and contraction. Such
lengthening and shortening can lead to a breakdown of the bond between the
casing and the surrounding cement. This degradation can lead to development of
fluid leak paths past (or through) the cement, and/or loss of structural
support
provided by the cement. Such issues may be particularly problematic in high
temperature, geothermal and steam injection wells. However, casing provided
with outer profiles (such as profiles 606 illustrated shown in Figures 6 and
7)
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CA 02610203 2007-11-13
interacts with the surrounding cement in the same way as the internal profiles
308
interact with compound 212 described above. Hence this casing is more robust
against axial stresses (such as thermally-induced stresses). Shear forces
within
the surrounding cement are better resisted due to the absence of stress risers
at
or near the casing-cement interface. Therefore, breakdown of the cement and/or
the casing-to-cement bond is hindered, thereby mitigating the above problems.
Further, an inner tubular profile (not shown) may be located at a
particular point on the inner diameter of a tubular string, or along the
entire inner
diameter of the tubular string. The inner tubular profile would act in a
similar
manner to the profiles 308, 604, and 606 described above. The inner tubular
profile may provide a landing point for tools to be run into the wellbore
after the
tubular string has been run in.
Further, the component 600 may be any suitable downhole tool secured
to the tubular 602 by a compound. For example the component may be a valve, a
baffle, a pressure transducer, a sensor, an actuator, a motor, a whipstock, or
electronics.
In an additional or alternative embodiment, the internal space of
apparatus 204/500/602 may be filled with compound 212, thereby forming a plug
without the component. Alternatively, the component 600 may be present, but
may include a solid component without a throughbore in order to assume the
configuration of a plug. The plug would act to restrict fluid flow between the
upstream and downstream portion of the plug, and would be able to hold
increased pressure on either side of the plug due to the stress reducing
capabilities of the internal profile portion 308.
CA 02610203 2007-11-13
While the foregoing is directed to embodiments of the present invention,
other and further embodiments of the invention may be devised without
departing
from the basic scope thereof, and the scope thereof is determined by the
claims
that follow.
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