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MONO DIAMETER WELLBORE CASING
Cross Reference To Related Applications
[001] The present application claims the benefit of the filing dates of (1)
U.S. provisional patent
application serial no. 60/380,147, attorney docket no 25791.104, filed on
5/06/2002, the disclosure of
which is incorporated herein by reference.
[002] The present application is related to the following: (1) U.S. patent
application serial no.
09/454,139, attorney docket no. 25791.03.02, filed on 12/3/1999, (2) U.S.
patent application serial no.
09/510,913, attorney docket no. 25791.7.02, filed on 2/23/2000, (3) U,S.
patent application serial no.
09/502,350, attorney docket no. 25791.8.02, filed on 2/10/2000, (4) U.S.
patent application serial no.
09/440,338, attorney docket no. 25791.9.02, filed on 11/15/1999, (S) U.S.
patent application serial no.
09/523,460, attorney docket no. 25791.11.02, filed on 3/10/2000, (6) U.S.
patent application serial no.
09/512,895, attorney docket no. 25791.12.02, filed on 2/24/2000, (7) U.S.
patent application serial no.
09/511,941, attorney docket no. 25791.16.02, filed on 2/24/2000, (8) U.S.
patent application serial no.
09/588,946, attorney docket no. 25791.17.02, filed on 6/7/2000, (9) U.S.
patent application serial no.
09/559,122, attorney docket no. 25791.23.02, filed on 4126/2000, (10) PCT
patent application serial
no. PCT/US00/18635, attorney docket no. 25791.25.02, filed on 7/9/2000, (11)
U.S. provisional
patent application serial no. 60/162,671, attorney docket no. 25791.27, filed
on 11/1/1999, (12) U.S.
provisional patent application serial no. 60/154,047, attorney docket no.
25791.29, filed on 9/16/1999,
(13) U.S. provisional patent application serial no. 60/159,082, attorney
docket no. 25791.34, filed on
10/12/1999, (I4) U.S. provisional patent application serial no. 60/159,039,
attorney docket no.
25791.36, filed on 10/12/1999, (15) U.S. provisional patent application serial
no. 60/159,033, attorney
docket no. 25791.37, filed on 10/12/1999, (16) U.S. provisional patent
application serial no.
60/212,359, attorney docket no. 25791.38, filed on 6/19/2000, (17) U.S.
provisional patent application
serial no. 601165,228, attorney docket no. 25791.39, filed on 11/12/1999, (18)
U.S. provisional patent
application serial no. 60/221,443, attorney docket no. 25791.45, filed on
7/28/2000, (19) U.S.
provisional patent application serial no. 60/221,645, attorney docket no.
25791.46, filed on 7/28/2000,
(20) U.S. provisional patent application serial no. 60/233,638, attorney
docket no. 25791.47, filed on
9/18/2000, (21) U.S. provisional patent application serial no. 60/237,334,
attorney docket no.
25791.48, filed on 10/2/2000, (22) U.S. provisional patent application serial
no. 60/270,007, attorney
docket no. 25791.50, filed on 2/20/2001, (23) U.S. provisional patent
application serial no.
60/262,434, attorney docket no. 25791.51, filed on 1/17/2001, (24) U.S,
provisional patent application
serial no. 60/259,486, attorney docket no. 25791.52, filed on 1/3/2001, (25)
U.S. provisional patent
application serial no. 60/303,740, attorney docket no. 25791.61, filed on
7/6/2001, (26) U.S.
provisional patent application serial no. 60/313,453, attorney docket no.
25791.59, filed on 8/20/2001,
(27) U.S. provisional patent application serial no. 60/317,985, attorney
docket no. 25791.67, filed on
9/6/2001, (28) U.S. provisional patent application serial no. 60/3318,386,
attorney docket no.
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25791.67.02, filed on 9/10/2001, (29) U.S. utility patent application serial
no. 09/969,922, attorney
docket no. 25791.69, filed on 10/3/2001, (30) U.S. utility patent application
serial no. 10/016,467,
attorney docket no. 25791.70, filed on 12/10/2001; (31) U.S. provisional
patent application serial no.
60/343,674, attorney docket no. 25791.68, filed on 12/27/2001; (32) U.S.
provisional patent
application serial no. 60/346,309, attorney docket no 25791.92, filed on
1/7/2002; (33) U.S.
provisional patent application serial no. 60/372,048, attorney docket no.
25791.93, filed on 4/12/2002;
and (34) U.S. provisional patent application serial no. 60/372,632, attorney
docket no. 25791.101,
filed on 4/15/2002, the disclosures of which are incorporated herein by
reference.
Background of the Invention
[003] This invention relates generally to oil and gas exploration, and in
particular to forming and
repairing wellbore casings to facilitate oil and gas exploration and
production.
[004] Conventionally, when a wellbore is created, a number of casings are
installed in the borehole
to prevent collapse of the borehole wall and to prevent undesired outflow of
drilling fluid into the
formation or inflow of fluid from the formation into the borehole. The
borehole is drilled in intervals
whereby a casing which is to be installed in a lower borehole interval is
lowered through a previously
installed casing of an upper borehole interval. As a consequence of this
procedure the casing of the
lower interval is of smaller diameter than the casing of the upper interval.
Thus, the casings are in a
nested arrangement with casing diameters decreasing in downward direction.
Cement annuli are
provided between the outer surfaces of the casings and the borehole wall to
seal the casings from the
borehole wall. As a consequence of this nested arrangement a relatively large
borehole diameter is
required at the upper part of the wellbore. Such a large borehole diameter
involves increased costs
due to heavy casing handling equipment, large drill bits and increased volumes
of drilling fluid and
drill cuttings. Moreover, increased drilling rig time is involved due to
required cement pumping,
cement hardening, required equipment changes due to large variations in hole
diameters drilled in the
course of the well, and the large volume of cuttings drilled and removed.
[005] The present invention is directed to overcoming one or more of the
limitations of the existing
processes for forniing and repairing wellbore casings.
Summary of the Invention
[006] According to one aspect of the present invention, an apparatus and
method fox forming a
mono diameter wellbore casing is provided.
Brief Description of the Drawings
[007] Figs. la-if are conceptual illustrations of one aspect of the present
invention.
[008] Figs. 2a-2f are fragmentary cross-sectional illustrations of the
placement of an exemplary
embodiment of an apparatus for forming a mono diameter wellbore casing within
a wellbore that
traverses a subterranean formation.
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[009] Figs. 3a-3f are fragmentary cross-sectional illustrations of the
apparatus of Figs. 2a-2f after
placement on the bottom of the wellbore.
[0010] Figs. 4a-4f are fragmentary cross-sectional illustrations of the
apparatus of Figs. 3a-3f after
placing a ball or dart within the ball or dart seat to initiate the radial
expansion and plastic
deformation of the expandable tubular member.
[0011] Figs. Sa-Sf are fragmentary cross-sectional illustrations of the
apparatus of Figs. 4a-4f after
the initiation of the radial expansion and plastic deformation of the aluminum
sleeve within the shoe.
[0012] Fig. 6a-6f are fragmentary cross sectional illustrations of the
apparatus of Figs. Sa-Sf after the
completion of the radial expansion and plastic deformation of the aluminum
sleeve within the shoe.
[0013] Figs. 7a-7f are fragmentary cross-sectional illustrations of the
apparatus of Figs. 6a-6f after
displacing the sliding sleeve valve within the shoe to permit circulation
around the ball or dart.
[0014] Figs. 8a-8f are fragmentary cross-sectional illustrations of an
alternative embodiment of a
bottom anchoring apparatus.
[0015] Figs. 9a-9g are fragmentary cross sectional illustrations of certain
aspects of the operation of
the apparatus of Figs. 8a-8f.
Detailed Description of the Illustrative Embodiments
[0016] Referring initially to Fig. la, an embodiment of an apparatus and
method for radially
expanding a tubular member will now be described. As illustrated iii Fig. la,
a wellbore 100 is
positioned in a subterranean formation 105. In an exemplary embodiment, the
wellbore 100 may
include a casing 110. The wellbore 100 may be positioned in any orientation
from vertical to
horizontal. Thus, in this application the direction "up", "upper" or "upward"
refers to the direction
towards the surface termination of the wellbore and the direction "down",
"lower" or "downward"
refers to the direction towards the bottom or end of the wellbore.
[0017] In order to extend the wellbore 100 into the subterranean formation
105, a drill string (not
shown) is used in a well known manner to drill out material from the
subterranean formation 105 to
form the wellbore 100. The inside diameter of the wellbore 100 is greater than
or equal to the outside
diameter of the casing 110.
[0018] In an exemplary embodiment, a tubular apparatus 120 having an opening
122 may then be
positioned within the wellbore 100 with an upper end 124a of the apparatus 120
initially coupled to a
well string 125. The apparatus 120 is adapted to allow fluidic materials to
enter the upper end 124a of
the tool and exit through the opening 122 positioned at the lower end 124b of
the tool, thereby
creating a passage (not shown) or fluid flow path 126. The apparatus 120 may
include, among other
components, a casing lock 130, a gripping device 132, a tension actuator 134,
a sealing mechanism
136, an expansion cone 140, a cementing probe 144, and a casing anchor 148,
[0019] The apparatus I20 as illustrated in Fig. Ia is in a "running" or
positioning configuration. In
other words, the tool is running or traveling down the wellbore. In several
exemplary embodiments,
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in the running configuration, the lower end I24b of the apparatus I20 extends
past the casing 110 into
the wellbore. The casing lock 130 may be used to support or couple the
apparatus 120 to the casing
110 which may keep the casing 110 positioned above the lower end 124b of the
tool when the
apparatus 120 is in the running configuration. Alternatively, the expansion
cone 140 may be used to
support the casing 110 during the running or positioning of the apparatus 120.
[0020] In one embodiment, the gripping device 132 may be positioned close to
the upper end 124a of
the apparatus 120. In the illustrative embodiment, the gripping device 132 is
positioned above the
casing lock 130. As will be explained in detail below, the gripping device 132
may be used to keep
the casing 110 stationary during the operation of the apparatus 120. A force
multiplier or tension
actuator 134 may be positioned below the casing lock 130. The tension actuator
134 may be used to
"pull" the expansion cone 140 and the lower end 124b of the apparatus 120
inside the casing 110. hi
the illustrative embodiment, an alternative sealing mechanism 136 may be
positioned below the
tension actuator 134.
[0021] As illustrated in Fig. la, an apparatus for radially expanding a
tubular member, such as an
expansion cone 140 may then be positioned outside of the casing 110. A tubular
member, such as a
cementing probe I44, may be positioned below the expansion cone 140. A casing
anchor 148, such
as a packer or drillable shoe, may be positioned at the lower end 124b of the
apparatus 120.
[0022] Turning now to Fig. lb, there is illustrated the apparatus 120
positioned at the bottom of the
wellbore 100. As will be explained in detail below, when the apparatus 120
contacts with the bottom
of the wellbore 100, an expansion mechanism 150, coupled to the casing anchor
148, expands radially
outwaxd such that the casing 110 cannot move past the expansion mechanism. In
one embodiment,
the expansion cone 140 may also expand upon impact with the bottom of the
well. The expansion
cone may expand to a diameter that is greater than the interior diameter of
the casing 110.
[0023] In an exemplary embodiment, as illustrated in Fig. lc, an actuating
event may occur to cause
the gripping device 132 to grip the casing 110. Such an actuating event may be
placing a plug, such
as a ball or dart into the apparatus 120 to block the flow path 126 and
prevent fluids from exiting
through opening 122. Injecting a fluidic material into the apparatus when the
flow path 126 is
blocked causes an increase in pressure within the tool. The increase pressure
may actuate gripping
elements of the gripping device 132 thereby locking the top end of the
apparatus I20 to the
expandable tubular member. In some alternative embodiments, the continued
injection of the fluidic
material furthermore increases the operating pressure within the tool which
causes the expansion cone
to expand, The increase operating pxessure may also cause the tension actuator
134 to pull the
expansion cone 140 ~to the expandable tubular member. As a result, the casing
or expendable casing
110 is radially expanded as the expansion cone 140 travels up the casing 110.
[0024] Turning now to Fig. ld, the continued upward movement of the expansion
cone 140 pulls the
casing anchor 148 into the end of the radially expanded casing 110. As a
result, the end of the
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radially expanded casing 110 will impact the expansion mechanism 150, thereby
preventing the
casing anchor 148 from moving further in the upward direction. lii some
embodiments, the continued
upward force on the casing anchor 148 may cause the casing anchor to radially
expand withiiz the
casing to firmly couple the end of the tubular member to the casing anchor
148. In alternative
embodiments, this anchoring may also hydraulically seal the anchor 148 to the
casing 110.
[0025] The continued upward force on the apparatus 120 may cause the cementing
probe 144 to
separate from the casing anchor 148, as illustrated in Fig. le. At the top of
the stroke, the casing loclc
130 (not shown) may be released. After separation, the apparatus 120 is free
to continue to advance up
causing the casing 110 to expand as necessary. Tf a hydraulic seal is created
between the anchor 148
and the casing 110, the region between the anchor and the sealing mechanism
136 may be
pressurized. This pressurized region forces the expansion cone upwardly,
thereby causing a radial
expansion and plastic deformation of the expandable casing 110. In this
manner, in the alternative
embodiment, the fluid pressure below the sealing mechanism 136 pulls the
expansion cone 140
upwardly through the expandable casing 110. Thus, the use of the tension
actuator 134 to pull the
expansion cone upwards is no longer necessary.
[0026] At some point (e.g., at the top of the liner), it may become desirable
to stop expanding and to
inject a hardenable fluidic sealing material such as, for example, cement into
the well annulus. To
begin the cementing operation, the apparatus 120 may be lowered into the
wellbore 100 tmtil the
cementing probe 144 couples to the casing anchor 148 as illustrated in Fig.
lf. This coupling opens a
bypass flowpath 154 to permit fluidic materials to bypass around the blockage
in flow path 126. As a
result, the bypass flow path 154 allows for cement or other fluidic materials
to flow around the
blockage of flow path 126.
[0027] Thus, the cement flows through the interior of the apparatus 120,
through the bypass flow
path 154, and out through a one-way valve (not shown) into the annulus between
the radially
expanded tubular member and the wellbore. After the cement has been injected
into the annulus, the
one way valve may prevent the cement from flowing backwards into the apparatus
120.
[0028] After completing the injection of the cement into the annulus, the
drilling pipe may then
pulled upwardly out of the wellbore. The radial expansion and plastic
deformation of the expandable
tubular member may then be continued by the resumed injection of fluidic
material into the apparatus.
After the cement has cured, the anchor 148 may be drilled out and another
expandable tubular
member may then be radially expanded and plastically deformed within the
wellbore with the upper
end of the other tubular member overlapping with the Iower end of the earlier
expanded tubular
member. In this manner, a mono diameter wellbore casing may be formed that
includes a plurality of
radially expanded tubular members.
[0029] Turning now to Figs. Za-2f, there is illustrated an exemplary
embodiment of an apparatus 200,
which illustrates certain aspects of the apparatus 120 discussed above. At the
upper end of the
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apparatus 200, there is the gripping device I32. In several exemplary
embodiments, the gripping
device 132 may be any device capable of engaging the inside surface of the
tubular member or casing
110 in a conventional manner and/or using one or more of the methods and
apparatus disclosed in one
or more of the following: (1) PCT application no. serial no. PCT/LTS02/36267,
attorney docket no.
25791.88, filed on 11/12/2002, (2) U.S. provisional patent application serial
no. 60/338,996, attorney
docket no. 25791.87, filed on 11/12/2001, (3) U.S. provisional patent
application serial no.
60/363,829, attorney docket no. 25791.95, filed on 3/13/2002, and (4) U.S.
provisional patent
application serial no. 60/339,013, attorney number attorney docket no.
25791.88, filed on 11/12/2001,
the disclosures of which are incorporated herein by reference. In the
embodiment as illustrated in
Figs. 2a-2f, the gripping device 132 comprises a tubular central mandrel 202
which defines a central
passage 203. The central mandrel 202 has an upper end 204a adapted to
threadably couple to and
receive within an end of the well strut g 12S in a conventional manner. A
tubular retaining sleeve 206
slidingly engages the central mandrel 202, such that the retaining sleeve 206
may move longitudinally
relative to the central mandrel 202 between an external annular upper flange
20Sa and an external
annular lower flange 20Sb projecting from the central mandrel 202. A pair of
concentric annular
recesses in the upper flange 205a form an annular guide flange 209 which fits
within the retaining
sleeve 206. The retaining sleeve 206 has an internal upper flange 207a and an
internal lower flange
207b. The upper flange 207a, the guide flange 209, the external surface of the
central mandrel 202
and the internal surface of the retaining sleeve 206 defines an annular upper
spring chamber 208a.
Similarly, the lower flange 20Sb, the lower flange 207b, the external surface
of the central mandrel
202 and the internal surface of the retaining sleeve 206 defines an annular
lower spring chamber 208b.
Helical springs 210a and 210b may be disposed within the upper and lower
retaining chambers 208a
and 208b, respectively to longitudinally position the retaining sleeve 206
relative to the central
mandrel 202.
[0030] A plurality of tapered recesses, for example recesses 212a-2124 are
defined in the external
surface of the central mandrel 202. Corresponding to each recess 212a-212d,
there is a tapered
circular opening, for instance circular openings 214a-214d, through the wall
of the retaining sleeve
206. The tapered recesses 212a-212d, the interior surface of the retaining
sleeve 206, and the circular
openings 2I4a-2I4d define retaining chambers 2I6a-216d, respectively. Hardened
gripping elements,
such as balls 218a-218d or spxag clutch elements, made from stauiless steel or
another hardened
material, may be positioned with the retaining chambers 216a-216d. In the
running configuration
illustrated in Figs 2a-2e, the springs 210a and 2IOb bias the sleeve 206 such
that the balls 218a-218d
remain in the widest portion of the tapered retaining chambers 216a-216d. In
this configuration, the
balls do not engage the interior surface of the casing or casing 110.
[003I] An annular pressure chamber 222 may be defined between the bottom of
the internal flange
207a of the retaining sleeve 206 and the top of an external annular flange
224. A sealing means, such
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as an O-ring or sealing cartridge 211 may provide a seal between the internal
flange 207a and the
exterior surface of the central mandrel 202. Additionally, a sealing means,
such as an O-ring or
sealing cartridge 213 may provide a seal between the side of the flange 224
and the exterior of the
central mandrel 202. A plurality of radial passages, for instance passages
220a and 220b may be
defined with the central mandrel 202 which provides fluid communication
between the central
passage 203 and the pressure chamber 222. Thus, the pressure of the pressure
chamber 222 remains
approximately the same as the pressure within the central passage 203. When
the pressure of the
central passage 203 is large enough to overcome the biasing of the springs
208an and 208b, the
pressure chamber 222 expands by driving the upper flange 207 away from the
external flange 224.
Thus, the upper flange 207 acts like a piston pushing the retaining sleeve 206
in an upperwardly
direction with respect to the central mandrel 202.
[0032] When the retaining sleeve moves up, the steel balls 218a-218d are
forced up into thinner
regions of the retaining chambers 216a-216d. A portion of the steels balls
218a-2184, therefore,
projects radially through the circular openings 214a-214d. As the steel balls
218a-218d project
through the circular openings 214a-214d, they engage the interior surface of
the casing 110. The balls
218a-218d grip the interior surface in proportion to the pressure applied to
the central passage 203.
The balls may create small concave indents that imparts a benign compressive
stress into the casing
110.
[0033] A lower end 204b of the central mandrel 202 may be adapted to
threadably couple to other
components or tools, such as the casing lock 130 or the tension actuator 134.
In the illustrative
embodiment, the lower end 204 is coupled to the tension actuator 134.
[0034] In several exemplary embodiments, the tension actuator 134 may be any
device capable of
pulling the expansion cone 140 into the casing 110 in a conventional manner
and/or using one or more
of the methods and apparatus disclosed in one or more of the following: (1)
PCT application no. serial
no. PCT/LTS02/36267, attorney docket no. 25791.88, filed on 11/12/2002, (2)
U.S. provisional patent
application serial no. 60/338,996, attorney docket no. 25791.87, filed on
11/12/2001, (3) U.S.
provisional patent application serial no. 60/363,829, attorney docket no.
25791.95, filed on 3/13/2002,
and (4) U.S. provisional patent application serial no. 60/339,013, attorney
number attorney docket no.
25791.88, filed on 11/12/2001, the disclosures of wluch are incorporated
herein by reference.
[0035] In the illustrative embodiment, the actuator 134 comprises actuator
barrel 250 having a top
end 252 adapted to threadably couple to the lower end 204b of the gripping
device 132. The actuator
barrel 250 defines a longitudinal passage 250a having an internal annulax
flange 250b at the lower end
of the longitudinal passage 250. The lower end of the actuator barrel 250
couples to a connector
barrel 254. The connector barrel 254 defines a longitudinal passage 254a
having an internal annular
flange 254b at the lower end of the longitudinal passage 254a. The lower end
of the connector barrel
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254 couples to a connector barrel 256. The connector barrel 256 defines a
longitudinal passage 256a
having an internal annular flange 256b at the lower end of the longitudinal
passage 256a.
[0036] A piston tube 260 runs through the passages 250x, 254a, and 256a of the
actuator barrel 250
and the connector barrels 254 and 256, respectively. The piston tube 260 may
define a longitudinal
passage 261. An external annular flange 262a is defined at the top end of the
piston tube 260. The
outside diameter of the annular flange 262a is slightly smaller than the
inside diameter of the
Longitudinal passage 250a such that the annular flange 262a can slide
longitudinally within the
longitudinal passage 250a. A sealing means, such as a sealing cartridge 264a
creates a seal between
the annular flange 262a and the interior surface of the longitudinal passage
250. Similarly a sealing
means, such as a sealing cartridge 266a creates a seal between the exterior
surface of the piston tube
260 and the flange 254b. An annular pressure chamber 268a may be defined
between the bottom of
the external flange 262 of the piston tube 260 and the top of the annular
flange 250b. Radial tubes
270a and 270b may connect the pressure chamber 268a to the longitudinal
passage 261 of the piston
tube 260.
[0037] An external annular flange 262b may be defined on the exterior of the
piston tube 260. The
outside diameter of the annular flange 262b is slightly smaller than the
inside diameter of the
longitudinal passage 254a such that the annular flange 262b can slide
longitudinally within the
longitudinal passage 254a. A sealing means, such as a sealing cartridge 264b
creates a seal between
the annular flange 262b and the interior surface of the longitudinal passage
254a. Similarly a sealing
means, such as a sealing cartridge 266b creates a seal between the exterior
surface of the piston tube
260 and the flange 254b. An annular pressure chamber 268b may be defined
between the bottom of
the external flange 262b of the piston tube 260 and the top of the annular
flange 254b. Radial tubes
270c and 270d may connect the pressure chamber 268b to the longitudinal
passage 261 of the piston
tube 260.
[0038] Similarly, an external annular flange 262c may be defined on the
exterior of the piston tube
260. 'The outside diameter of the annulax flange 262c is slightly smaller than
the inside diameter of
the longitudinal passage 256a such that the annular flange 262c can slide
longitudinally within the
longitudinal passage 256a. Optionally, a sealing means, such as a sealing
cartridge 264c creates a seal
between the annular flange 262c and the interior surface of the longitudinal
passage 256a. Similarly a
sealing means, such as a sealing cartridge 266c creates a seal between the
exterior surface of the
piston tube 260 and the flange 256b. An annular pressure chamber 268c may be
defined between the
bottom of the external f<ange 262c of the piston tube 260 and the top of the
annular flange 256b.
Radial tubes 270e and 270f may connect the pressure chamber 268b to the
longitudinal passage 261
of the piston tube 260.
[0039] A lower end 272 of the piston tube may be adapted to be coupled to
another component, such
as the casing lock 130. Optionally, the casing lock 130 may be positioned
above the actuator 130. In
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several exemplary embodiments, the casing lock 134 may be any device capable
of coupling the
apparatus to the casing while the apparatus is being positioned within the
wellbore in a conventional
mamler and/or using one or more of the methods and apparatus disclosed in one
or more of the
following: (1) PGT application no. serial no. PCT/US02/36267, attorney docket
no. 25791.88, filed on
11/12/2002, (2) U.S. provisional patent application serial no. 60/338,996,
attorney docket no.
25791.87, filed on 11/12/2001, (3) U.S. provisional patent application serial
no. 60/363,829, attorney
docket no. 25791.95, filed on 3/13/2002, and (4) U.S. provisional patent
application serial no.
60/339,013, attorney number attorney docket no. 25791.88, filed on 11/12/2001,
the disclosures of
which are incorporated herein by reference.
[0040] Fig. 2d illustrates an alternative embodiment where a sealing means
136, such as a packer cup
assembly may provide a way to create a pressurized zone within the casing 110.
In several exemplary
embodiments, the sealing means 136 may be any device capable of sealing
between differential zones
of pressure in a conventional manner and/or using one or more of the methods
and apparatus
disclosed in one or more of the following: (1) PCT application no. serial no.
PCT/L1S02/36267,
attorney docket no. 25791.88, filed on 11/12/2002, (2) U.S. provisional patent
application serial no.
60/338,996, attorney docket no. 25791.87, filed on 11/12/2001, (3) U.S.
provisional patent application
serial no. 60/363,829, attorney docket no. 25791.95, filed on 3/13/2002, and
(4) U.S. provisional
patent application serial no. 60/339,013, attorney number attorney docket no.
25791.88, filed on
11/12/2001, the disclosures of which are incorporated herein by reference.
[0041] For instance, an upper packer cup assembly 280 may be coupled to a
mandrel 282 proximate
the upper end of the mandrel 282. The mandrel 282 may define an longitudinal
passage 283. In an
exemplary embodiment, a packer cup 284 may be a GuibersonTM packer cup.
Optionally, a spacer
sleeve (not shown) may mate with, receives, and may be coupled to the mandrel
282 proximate an end
of the upper packer cup assembly 280. A lower packer cup assembly 286 may be
coupled to the
mandrel 282. In an exemplary embodiment, a lower packer cup 286 is a
GuibersonTM packer cup.
Optionally, a lower spacer sleeve may be coupled to the mandrel 282 to
longitudinally position the
lower packer assembly 286.
[0042] An expansion cone 140 may be positioned below the sealing means 136. In
several
exemplary embodiments, the expansion cone I40 may be any device capable of
expanding the casing
or tubing member 110 within the wellbore 105 in a conventional manner and/or
using one or more of
the methods and apparatus disclosed in one or more of the following: (1) PCT
application no. serial
no, PCT/US02/36267, attorney docket no. 25791.88, filed on I I/12/2002, (2)
U.S. provisional patent
application serial no. 60/338,996, attorney docket no. 25791.87, filed on
11/12/2001, (3) U.S.
provisional patent application serial no. 60/363,829, attorney docket no.
2579I.95, filed on 3/I3/2002,
and (4) U.S. provisional patent application serial no. 60/339,013, attorney
number attorney docket no.
25791.88, filed on 11/12/2001, the disclosures of which are incorporated
herein by reference.
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[0043] In an exemplary embodiment, an adjustable expansion cone may be similar
to a conventional
adjustable expansion mandrel in that may be expanded to a larger outside
dimension or collapsed to a
smaller outside dimension and includes external surfaces for engaging the
casing 110 to thereby
radially expand and plastically deform the tubular member when the adjustable
expansion mandrel is
expanded to the larger outside dimension. In an alternative embodiment, the
expansion cone 140 may
include a rotary adjustable expansion device such as, for example, the
commercially available rotary
expansion devices of Weatherford International, Inc. In several alternative
embodiments, the cross
sectional profile of the expansion cone 140 for radial expansion operations
may, for example, be an n-
sided shape, where n may vary from 2 to infinity, and the side shapes may
include straight line
segments, arcuate segments, parabolic segments, and/or hyperbolic segments. In
several alternative
embodiments, the cross sectional profile of the adjustable expansion cone 140
may, for example, be
circular, oval, elliptical, and/or multifaceted.
[0044] Alternatively, the expansion cone 140 may be comprised of a plurality
of circumferentialy
spaced apart upper cone segments interleaved among the cam arms of an upper
cam spaced around a
mandrel 291 defining longitudinal passage 293. In an exemplary embodiment,
each upper cone
segment includes a first outer surface that defines a hinge groove, a
plurality of inner surfaces and a
plurality of outer surfaces. In an exemplary embodiment, there may be a
combination of axcuate and
cylindrical segments. 'The upper cone segments may be pivotally coupled to an
upper cone retainer
290. A plurality of circumferentialy spaced apart lower cone segments
interleaved among the cam
arms of a lower cam. In an exemplary embodiment, each lower cone segment
includes a first outer
surface that defines a hinge groove, a plurality of inner surfaces and a
plurality of outer surfaces. In
an exemplary embodiment, there may be a combination of arcuate and cylindrical
segments. The
lower cone segments may be pivotally coupled to a lower cone retainer 292.
Shear pins or another
retaining mechanism longitudinally position the lower retainer 292 relative to
the upper retainer 290
such that they remain positioned apart during the positioning of the apparatus
within the well. In one
embodiment, when the apparatus reaches the bottom of the well, the impact
shears the shear pins and
drives the lower cone retainer toward the upper cone retainer, causing the
cone segments to pivot
outward in a lateral direction. As the cone segments pivot outward, the
diameter of the expansion
cone 140 increases. A locking mechanism then locks the cone segments together
in an expanded
configuration.
[0045] The lower cone retainer 292 receives and may be threadably coupled to
an end of a release
housing 300 that defines a longitudinal passage 302. A lower end 304 of the
release housing 300
defines a external flange 305 adapted to mate into a sleeve 306 in the
anchoring device 148. In some
exemplary embodiments, a tubular cementing pxobe 308 may be slidingly disposed
within the
longitudinal passage 302. The cementing probe 308 may be a tubular shaped
member which defines a
longitudinal passage 310. A top end of the cementing probe 308 has an annular
exterior flange or rim
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312, the diameter of which is slightly smaller than the interior diameter of
the longitudinal passage
302. During operation, an interior annular seat 314 defined within the release
housing 300 keeps the
flange 312 of cementing probe within the longitudinal passage 302. A lower end
of the concrete
probe narrows to form a neck 316 which, as will be explained below, is adapted
to mate with a collet
of the anchoring device 148. During positioning of the apparatus, a probe
shear pin 318 longitudinally
retains the sliding sleeve within the longitudinal passage 302. Once the
cement probe 308 has been
extended during operation, however, a probe locking ring 320 may maintain the
probe in an extended
configuration.
[0046] In the illustrative embodiment, the anchoring device 148 may be a an
expandable float shoe
340. In some exemplary embodiments, the float shoe 340 may be made out of
aluminum or another
expandable material which may be relative easy to drill out. The top end of
the float shoe defines a
tubular sleeve 342 defining an annual passage 344. The tubular sleeve 342 is
adapted to mate within
the release housing 300. A sliding sleeve valve 346 is slidingly disposed
within the longitudinal
passage 344.
[0047 The sliding sleeve valve 346 is generally tubular in shape defining an
longitudinal passage
348. At a top end of the sliding sleeve valve 346, there is an outwardly
protruding flange or rim 350
which circumferentially extends around the top end of sliding sleeve valve
346. Below the rim 350,
there is a flexible or top section defining a collet 346a. Below the collet
346a, there is a lower section
346b of the sliding sleeve valve 346. The wall thickness of the collet 346a is
narrow relative to the
lower section 346b. There are also a predetermined number of longitudinal
slots (not shown)
extending from the top of the rim 350 through the collet 346a. Preferably
these longitudinal slots are
equally spaced around the periphery of the collet 346a. The combination of the
longitudinal slots and
the narrowed wall thickness of the collet 346a allow the diameter of the rim
350 to decrease when the
rim 350 is not radially supported by a supporting mechanism. Thus, the rim 350
can be considered
"flexible" in that it can contract from a first radial position of a
particular diameter to a second radial
position of a lesser diameter. In the running configuration illustrated in
Fig. 2f, the rim 350 is
positioned in an interior recess 352 defined in the sleeve 342. The neck 316
of the cementing probe
308 radially supports rim 350, preventing the rim 350 from slipping out of the
recess 352 and thus
longitudinally maintains the sliding sleeve valve 346 within the sleeve 342. A
side port 354 may be
defined within the side wall of the lower section 346b.
[0048] In several exemplary embodiments, there is a annular seat 35S
positioned within the
longitudinal passage 344 of the float shoe 340. The annular seat 355 is
adapted to sealingly couple to
a plug. The plug may be any conventional plug, such as drill pipe dart or
phenolic ball that would
provide a hydraulic seal upon reaching the annular seat 355. The sleeve 342 of
the float shoe 340
increases in diameter to accommodate a bypass passage 356. The bypass passage
356 defines a
passage that connects the portion of the longitudinal passage 344 above the
seat 356 to a portion of
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the longitudinal passage 344 below the seat 356, thereby creating a "bypass"
around the seat 356. In
the running position illustrated in Figs. 2a-2e, an entrance port 356a of the
bypass passage 356 is
blocked by the sliding sleeve valve 346.
[0049] Positioned below the annular seat 355 is a one-way valve 358. In
several exemplary
embodiments, the one way valve 358 may be a float valve assembly which allows
for a fluid to flow
in a dovcn~ward direction, but prevents fluid to flow in an upward direction.
The one-way valve 358
opens into an longitudinal passage 360. A sleeve, such as a dog locking sleeve
362 may be slidingly
disposed within the longitudinal passage 360. A shear pin 364 maintains the
relative position of the
dog locking sleeve relative to the float shoe 340 such that a lower end 368 of
the dog locking sleeve is
disposed below the float shoe 340. At the fop end of the dog locking sleeve
362, there is an external
flange 366 adapted such that an upward movement by the external flange 366
"expands" or pushes
out a plurality of dogs 370 through a plurality of radial side openings 372
defined in the float shoe
340. In several alternative embodiments, the dogs 370 or expansion mechanism
150 within the float
shoe 340 may be replaced by a shoulder on the float shoe for engaging the end
of the radially
expanded tubular member.
[0050] In an exemplary embodiment, during operation of the apparatus 200, as
illustrated in Figs. 2a-
2e, the appaxatus may be initially positioned in the wellbore 100, partially
within the casing 110, with
the expansion cone 140, the cementing probe 144, and the float shoe 340
positioned outside the
casing. In this manner, fluidic materials within the interior of the apparatus
200 may pass through the
longitudinal passages 203, 250a, 261, 283, 293, 302, 310, 344, 348, and 360
out of the apparatus
through the float valve 358, into the annulus between the apparatus 200 and
the casing 110 thereby
preventing over pressurization of the annulus.
[0051] Referring now to Figs. 3a-3e, there is illustrated the apparatus 200
positioned at the bottom of
the wellbore 100. When the apparatus 200 contacts with the bottom of the
wellbore 100, the dog
locking sleeve 368 is driven up into the float shoe 340, shearing the shear
pin 360. The upward
movement of the locking sleeve 368 forces the dogs 370 through the side
openings 372, where a
locking mechanism prevents their retraction.
[0052] In an alternative embodiment of the expansion cone, the force of impact
with the bottom of
the well shears the retaining mechanism, forcing the lower expansion cone
retainer 292 towards the
upper expansion cone retainer 290. The interleaved cone segments pivot outward
in a Iatexal direction
on top of one another. As the cone segments pivot outward, the diameter of the
expansion cone 140
increases. A locking mechanism then locks the upper cone segments in place.
Thus, the expansion
cone may expand to a diameter that is greater than the interior diameter of
the casing 110.
[0053] Referring now to Figs. 4a-4f, there is illustrated the apparatus 200
when a plug, such as a ball
374 is then injected into the apparatus with the fluidic material through the
passages 203, 250a, 261,
283, 293, 302, 310, 344 and 348 until the dart is positioned and seated on the
annular seat 355 in the
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float shoe 340. As a result of the positioning of the ball 374 in the passage
344 of the float shoe 340,
the passage 344 of the float shoe is thereby closed.
[0054] The fluidic material is then injected into the apparatus thereby
increasing the operating
pressure within the passages 203, 250a, 261, 283, 293, 302, 310, 344 and 348.
Furthermore, the
continued injection of the fluidic material into the apparatus 200 causes the
fluidic material to pass
through the radial passages 220a and 220b, into the annular pressure chamber
222 of the gripping
device 132. When the pressure of the central passage 203 is large enough to
overcome the biasing of
the springs 208a and 208b, the pressure chamber 222 expands by driving the
upper flange 207 away
from the external flange 224. Thus, the upper flange 207a acts like a piston
pushing the retaining
sleeve 206 in an upperwardly direction with respect to the central mandrel
202. When the retaining
sleeve moves up, the steel balls 218a-218d are forced up into thinner regions
of the retaining
chambers 216a-216d. A portion of the steels balls 218a-2184, therefore,
projects radially through the
circular openings 214a-214d. As the steel balls 218a-218d project through the
circular openings
214a-214d, they engage the interior surface of the casing 110.
[0055] The fluidic material is then injected into the apparatus thereby
increasing the operating
pressure within the passages 203, 250a, 261, 283, 293, 302, 310, 344 and 348.
Furthermore, the
continued injection of the fluidic material into the apparatus 200 also causes
the fluidic material to
pass through the radial tubes 270a through 270f, of the piston tube 260 into
an annular pressure
chambers 268, 268a, and 268b, respectively.
[0056] The pressurization of the annular pressure chambers, 268a, 268b, and
268c then cause the
piston flanges 262a, 262b, 262c to be displaced upwardly relative to the
casing 100. As a result, the
upper packer cup assembly 280, the lower packer cup assembly 286, expansion
cone 140, the release
housing 300, the cementing probe 308, and the float shoe 340 are displaced
upwardly relative to the
casing 110.
[0057] The continued injection of the fluidic material into the apparatus 200
continues to pressurize
annular pressure chambers, 268a, 268b, and 268c. The further upward
displacement of the piston
flanges 262a, 262b, 262c in turn displaces the expansion cone 140 upwardly
relative to the casing
110. As a result, the expansion cone 140 radially expands and plastically
deforms a portion of the
casing 1I0.
[0058] Referring to Figs. 5a-5f, during the continued injection of the fluidic
material, the expansion
cone 140 will continue to be displaced upwardly relative to the casing 110
thereby continuing to
radially expand and plastically deform the casing until the Locking dogs 370a-
370b engage the lower
end of the casing 110. The continued upward movement of the expansion cone
140, cement probe
308, and release housing 300 causes the release housing 300 to move
longitudinally upward - out of
the sleeve 306 of the float shoe 340. The external flange 305 of the release
housing 300 causes the
sleeve 306 to radially expand against the casing 110. In some embodiments,
this radial expansion of
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the sleeve 306 also causes an expansion and plastic deformation of a portion
of the casing 110 wluch
may also hydraulically seal the sleeve 306 to the casing I10. Optionally, a
elastomeric sealing
material may be applied to the exterior of the sleeve 306 to create a seal
between the sleeve 306 and
the casing I 10.
[0059] Referring to Figs. 6a to 6e, The continued upwaxd movement of the
expansion cone 140,
cement probe 308, and release housing 300 causes the probe shear pin 318 to
shear. The force on the
cement probe 308 pulls the probe downward until the external flange 312
impacts the seat 314 defined
with the passage 302 preventing further movement of the cement probe. A probe
lock ring 313
disposed on the exterior surface of the concrete probe contacts a downward
facing seat 315, thereby
"locking" the concrete probe in place. The continued upward movement of the
cement probe 308
causes the cement probe 308 to separate from the float shoe 340. At the top of
the stroke of the
tension actuator 134, the casing lock 130 rnay be released. After separation,
the apparatus 200 is free
to continue to advance up causing the casing 110 to expand as necessary.
Because there is an
hydraulic seal between the sleeve 306 and the casing 110, the region between
the float shoe 340 and
the packer cup assemblies 280 and 286 may be pressurized. This pressurized
region forces the
expansion cone 140 upwardly, thereby causing a continued radial expansion and
plastic deformation
of the expandable casing 110. In this manner, the fluid pressure below the
packer cup assemblies 280
and 286 pulls the expansion cone 140 upwardly through the expandable casing
110. Thus, the use of
the tension actuator 134 to pull the expansion cone upwards is no longer
necessary.
[0060] At some point (e.g., at the top of the liner), it may become desirable
to stop expanding and to
inject a hardenable fluidic sealing material such as, for example, cement into
the well annulus.
Referring to Figs. 7a to 7f, to begin the cementing operation, the apparatus
200 may be lowered into
the wellbore 100 until the neck 316 of the cementing probe 308 impacts the
collet 346a forcing the
rim 350 of the collet from the recess 352, which allows the sliding sleeve
valve 346 to move
downward until the sliding sleeve valve impacts an upward facing seat 345 in
the passage 344. In this
position, the sideport 354 is aligned with the opening of the bypass flowpath
356 to permit fluidic
materials to bypass around the ball in the passage 344. As a result, the
bypass flow path 356 allows
for cement or other fluidic materials to flow around the ball.
[0061] Thus, the cement may flow through the through the bypass flow path 356,
and out through the
one-way valve 358 into the annulus between the radially expanded tubular
member and the wellbore.
After the cement has been injected into the annulus, the one way valve may
prevent the cement from
flowing backwards into the flowpath 356.
[0062] After completing the injection of the cement into the annulus, the
drilling pipe may then
pulled upwardly out of the wellbore. The radial expansion and plastic
deformation of the expandable
tubular member may then be continued by the resumed injection of fluidic
material into the apparatus.
After the cement has cured, the float shoe 340 may be drilled out and another
expandable tubular
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member may then be radially expanded and plastically deformed within the
wellbore with the upper
end of the other tubular member overlapping with the lower end of the earlier
expanded tubular
member. In this manner, a mono diameter wellbore casing may be formed that
includes a plurality of
radially expanded tubular members.
[0063] In several alternative embodiments, a packer may be used instead of the
float shoe 340 to
couple the end of the casing to the apparatus. Refezring to Figs. 8a to 8e, an
alternative embodiment,
an apparatus S00 for forming a mono diameter wellbore casing SOZ provides a
one step monobore
wellbore casing radial expansion system. 'The one step monobore system can
also be used as a cased
or open hole radial expansion system, or an open hole cladding system where an
expandable casing is
clad against a formation in open hole.
[0064] In an exemplary embodiment, the apparatus S00 includes an expansion
assembly 504 and a
packer 506. The expansion assembly S04 includes, among other things, a safety
sub 508, a gripping
device S I0, a casing lock device S 12, a force multiplier or tension actuator
S 14, an expansion cone
S 16, a packer setting sleeve S 18, an internal sleeve S20 and a stinger 522.
[0065) In an exemplary embodiment, the safety sub S08 allows a quick
connection and disconnection
of the drill string to and from the expansion system.
[0066] In several exemplary embodiments, the gripping device S 10 may be any
device capable of
engaging the inside surface of the tubular member or casing S02 in a
conventional manner and/or
using one or more of the methods and apparatus disclosed in one or more of the
following: (1) PCT
application no. serial no. PCT/LTS02/36267, attorney docket no. 25791.88,
filed on 11/12/2002, (2)
U.S. provisional patent application serial no. 60/338,996, attorney docket no.
25791.87, filed on
11/12/2001, (3) U.S. provisional patent application serial no. 60/363,829,
attorney docket no.
25791.95, filed on 3/13/2002, and (4) U.S. provisional patent application
serial no. 60/339,013,
attorney number attorney docket no. 25791.88, filed on 11/12/2001, the
disclosures of which are
incorporated herein by reference. In the embodiment as illustrated in Figs. Sa-
8f, the gripping device
S 10 comprises hydraulic slips S l0a -S l Oc are isolated from internal
pressure by a rupture disc 524. In
an exemplary embodiment, a packer cup 526 acts as a check valve to allow
external pressure to
equalize behind the hydraulic slips S 10a -S l Oc when in a running
configuration, but holds internal
pressure when the rupture disc is ruptured. In an exemplary embodiment, the
hydraulic slips SlOa-
SlOc are actuated by rupturing the rupture disc S24 with internal pressure. In
an exemplary
embodiment, the internal pressure then acts on the hydraulic slips S l0a-S l
Oc, moving them out
against the internal diameter of the expandable casing 502. The hydraulic
slips SlOa-SlOc thereby
provide an anchor for the tension actuator to pull the expansion cone S04
against and expand the
expandable casing. When the internal pressure is released, the hydraulic slips
SlOa-SlOc retract away
from the internal diameter of the expandable casing 502.
CA 02484966 2004-11-05
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[0067] W an exemplary embodiment, a casing lock 512 holds the weight of the
expandable casing
string as it is run in the well. In several exemplary embodiments, the casing
lock 512 may be any
device capable of coupling the apparatus to the casing while the apparatus is
being positioned within
the wellbore in a conventional manner and/or using one or more of the methods
and apparatus
disclosed in one or more of the following: (1) PCT application no. serial no.
PCT/US02/36267,
attorney docket no. 25791.88, filed on 11/12/2002, (2) U.S. provisional patent
application serial no.
60/338,996, attorney docket no. 25791.87, filed on 11/12/2001, (3) U.S.
provisional patent application
serial no. 60/363,829, attorney docket no. 25791.95, filed on 3/13/2002, and
(4) U.S. provisional
patent application serial no. 60/339,013, attorney number attorney docket no.
25791.88, filed on
11/12/2001, the disclosures of which are incorporated herein by reference.
[0068] In the illustrative embodiment, casing lock dogs 530 fit in upsets
formed in the internal
diameter of the expandable casing and are held in place with a retaining
sleeve 532. When the
retaining sleeve 532 is shifted by the tension actuator 514, the dogs 530
retract and the expansion 504
is released from the expandable casing 502.
[0069) In several exemplary embodiments, the tension actuator 514 may be any
device capable of
pulling the expansion cone 140 into the casing 110 in a conventional manner
and/or using one or more
of the methods and apparatus disclosed in one or more of the following: (1)
PCT application no. serial
no. PCT/US02/36267, attorney docket no. 25791.88, filed on 11/12/2002, (2)
U.S. provisional patent
application serial no. 60/338,996, attorney docket no. 25791.87, filed on
11/12/2001, (3) U.S.
provisional patent application serial no. 60/363,829, attorney docket no.
25791.95, filed on 3/13/2002,
and (4) U.S. provisional patent application serial no. 60/339,013, attorney
number attorney docket no.
25791.88, fled on 11112/2001, the disclosures of which are incorporated herein
by reference. The
tension actuator 514 may also be similar to the tension actuator 134 described
above.
[0070] In an exemplary embodiment, the tension actuator 514 provides several
stages of differential
area for internal pressure to act upon and thereby provide an upward force to
the expansion cone 504
to thereby expand the expandable casing 502. The tension actuator 514 may be
used to initially
expand the expandable casing 502 and to pull the packer 506 into the radially
expanded casing 502.
The tension actuator 514 may be used at any time during radial expansion
process when the hydraulic
slips S 10a-S l ob are actuated to provide additional upward force to the
expansion cone. In an
exemplary embodiment, the tension actuator 514 may be used to assist in the
radial expansion process
when the portion of the expandable casing that overlaps with another casing is
radially expanded and
plastically deformed.
[0071] In several exemplary embodiments, the expansion cone 504 be any device
capable of
expanding the casing or tubing member 110 within the wellbore 105 in a
conventional manner and/or
using one or more of the methods and apparatus disclosed in one or more of the
following: (1) PCT
application no. serial no. PCT/LTS02/36267, attorney docket no. 25791.88,
filed on 11/12/2002, (2)
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U.S. provisional patent application serial no. 60/338,996, attorney docket no.
25791.87, filed on
11/12/2001, (3) U.S. provisional patent application serial no. 60/363,829,
attorney docket no.
25791,95, filed on 3/13/2002, and (4) U.S. provisional patent application
serial no. 60/339,013,
attorney number attorney docket no. 25791.88, filed on 11/12/2001, the
disclosures of which are
incorporated herein by reference.. Thus, the expansion cone S 16 may be an
adjustable expandable
expansion cone, or it may be expandable or non-expandable for use in cased or
open hole expansion
systems or open hole clad systems..
[0072] In an exemplary embodiment, an internal sleeve S34 blocks ports S36
which lead from the
internal passage 528 to the packer setting sleeve 538. In an exemplary
embodiment, the internal
sleeve 534 may be moved away from the ports 536 by the tension actuator SI4 at
the end of the
tension actuator stroke to allow internal pressure to act on the packer
setting sleeve S38 and thereby
set the packer 506 in the expanded casing 502. Thus, in an exemplary
embodiment, the packer setting
sleeve 538 is moved downwardly against the packer 506 to set the packer by
internal pressure.
[0073] In an exemplary embodiment, the packer S06 may be a fas dril packer
which is a composite
drillable packer that is set in the expanded casing and contains the expansion
pressure. The fas dril
packer includes an internal pressure balanced sliding sleeve valve 540 which
is used to open and close
fluid ports S42 The sleeve valve S40 has two external seals which seal against
the internal diameter
of the fas dril packer and isolate fluid ports in the fas dril packer when the
sleeve valve is in the up
position. When the sleeve valve is moved downwardly, ports 544 in the sleeve
valve 540 align with
ports S42 in the fas dril packer and allow fluid to be displaced into a bypass
passage S46 in the fas dril
packer. Collets at the top of the sleeve valve fit in an internal groove
provided in the internal diameter
of the fas dril packer when the sleeve valve is in the up position and allow
the end of the stinger to
pass and shoulder against the sleeve valve. When a stinger S48 pushes the
sleeve valve S40
downwardly to open the ports 542, the collets are pulled out of the groove and
retract inward into an
external undercut on the bottom of the stinger 548.
[0074] When the stinger S48 is moved up to close the ports 542, a lower
shoulder on the external
undercut contacts the inward retracted collets and pulls the sliding sleeve
valve S40 upwardly until the
collets expand out into the internal groove, The sleeve valve 540 is operated
with a stinger 548
attached to the expansion assembly 504. Below the sleeve valve S40 are two
ball seats SSOa and SSOb
with a rupture disc SS2 hi between. The bypass passage S46 connects the ports
S42 covered by the
sleeve valve, the rupture disc ports 554, and ports 556 positioned below the
bottom ball seat.
[0075] A check valve S58 may be disposed at the bottom of the fas dril packer.
Other types of
commercially available drillable packers may also be used, such as, for
example, the EZ Drill.
Additionally, for open and cased hole cladding systems where cement is not
going to be used,
retrievable packers can be used and retrieved after expansion instead of
drilled.
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[0076] In an exemplary embodiment, the stinger S48 may be attached to the
expansion assembly S04
and includes an external seal 560 which seals against the inside diameter of
the fas dril packer. At the
bottom end of the stinger is an external undercut which is used to close the
sliding sleeve valve.
[0077] Turning now to Figs. 9a-9e, which illustrates some aspects of the
operation of the apparatus
500. In Fig. 9a, the expansion assembly S04 is run through the casing 502
until the packer 506 is in
open hole beyond the casing.
[0078] A first plug, which may be a ball or a dart, may be dropped to the plug
seat SSOa in the packer
central passage 528. Continued pumping of fluids causes the internal pressure
to be increased. As
described above with reference to figs. la to 7f, the pressure actuates the
tension actuator S14 which
pulls the expansion cone 516 up against the bottom of the casing S 10.
[0079] The expansion cone 516 expands in size and then expands the expandable
casing 502, pulling
the packer 506 upwardly along with it. Near the end of the tension actuator
stroke, the packer 506 is
positioned in the expanded casing and the lower end of the tension actuator
shoulders against the
internal sleeve 520, shifting it downward. As a result, the ports S36 open
allowing fluidic
communication from the central passage 528 to the packer setting sleeve 538.
The internal pressure
then causes the setting sleeve S38 to down, which pushes against and sets the
packer 506.
[0080] The tension actuator 514 then pulls against a connecting mechanism,
such as a plurality of
shear pins, connecting the packer 506 to the expansion assembly 504 until they
shear.
[0081] At the end of the tension actuator stroke, an upper end S62 of the
tension actuator S14
shoulders against the dog retaining sleeve 532 and moves it upward, releasing
the dogs 530 and
unlocking the expansion assembly 504 from the casing 502.
[0082] Continued injection of the fluidic material into the apparatus 500
causes an increase in the
internal pressure in the central passage 528. The increase pressure ruptures
the rupture disc SS4,
which allows the fluid to flow into the bypass passage 546. The casing S02 can
now be run to the
bottom of the well.
[0083] Once the casing has reached the bottom of the well, a second plug may
be dropped. The
second plug sized to sealingly fit the second plug seat SSOb. The second plug
stops circulation
through the bypass passage 546. Continued injection of fluid increases the
internal pressure in the
central passage S28 so that the casing expansion can be partially or
completely continued, or the
expansion assembly can be set down to open the sliding sleeve valve to
circulate mud or displace
cement. Picking back up on the expansion assembly 504 will close the sliding
sleeve valve. At any
point during expansion, the expansion assembly S04 can be set down on the
packer S06 to open the
sliding sleeve valve S40 to continue circulation.
[0084] Once the expansion assembly 504 reaches an overlap section of the
expandable casing 502,
the expansion pressure increases until the upper rupture disc S24 ruptures.
The hydraulic slips SlOa-
S lOc then move out against the internal diameter of the expandable casing
502, providing an anchor
18
CA 02484966 2004-11-05
WO 03/093623 PCT/US03/14153
for the tension actuator to pull the expansion cone against. When the tension
actuator 514 reaches the
end of its stroke, the internal pressure is released, the hydraulic slips S
l0a-S l Oc retract, and the
tension actuator 514 is extended for another stroke. In an exemplary
embodiment, the hydraulic slips
SlOa-SlOc may be designed to not only contact the unexpended casing, but will
also extend out far
enough the contact the previously expanded casing string at the final
expansion stroke.
[0085] After the expansion assembly 504 is pulled out of the well, the packer
506 may be drilled out
and another section of hole may be drilled. An identical expansion system is
then run and expanded
to the same ID as the previous string.
[0086] It is understood that variations may be made in the foregoing without
departing from the
scope of the invention. For example, the teachings of the present illustrative
embodiments may be
used to provide a wellbore casing, a pipeline, or a structural support.
Furthermore, the elements and
teachings of the various illustrative embodiments may be combined in whole or
in part in some or all
of the illustrative embodiments.
[0087] It is understood that variations may be made in the foregoing without
departing from the
scope of the invention. For example, the teachings of the present illustrative
embodiments may be
used to provide a wellbore casing, a pipeline, or a structural support.
Furthermore, the elements and
teachings of the various illustrative embodiments may be combined in whole or
iiz part in some or all
of the illustrative embodiments.
[0088] Although illustrative embodiments of the invention have been shown and
described, a wide
range of modification, changes and substitution is contemplated in the
foregoing disclosure. In some
instances, some features of the present invention may be employed without a
corresponding use of the
other features. Accordingly, it is appropriate that the appended claims be
construed broadly and in a
manner consistent with the scope of the invention.
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