Note: Descriptions are shown in the official language in which they were submitted.
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MONO-DIAMETER WELLBORE CASING
Cross Reference To Related Applications
The present application claims the benefit of the filing date of U.S.
provisional patent application serial
no. 60/326,886, attorney docket no. 25791.60, filed on 10/03/2001, the
disclosure of which is incorporated
herein by reference.
This application is a continuation-in-part of: (1) U.S. utility application
serial number 09/454,139,
attorney docket number 25791.3.02, filed on 12/3/1999, which claimed the
benefit of the filing date of U.S.
provisional patent application serial number 60/1 I 1,293, attorney docket
number 25791.3, filed on 12/7/1998,
and (2) U.S. provisional application serial number 60/262,434, attorney docket
number 25791.51, filed on
1/17/2001, the disclosures of which are incorporated herein by reference.
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, (5) PCT patent application serial no.
PCT/LJS01/04753, attorney docket no.
25791.10.02, filed on 2/14/2001, (6) U.S. patent application serial no.
09/523,460, attorney docket no.
25791.11.02, filed on 3/10/2000, (7) U.S. patent application serial no.
09/512,895, attorney docket no.
25791.12.02, filed on 2/24/2000, (8) U.S. patent application serial no.
09/511,941, attorney docket no.
25791.16.02, filed on 2/24/2000, (9) U.S. patent application serial no.
09/588,946, attorney docket no.
25791.17.02, filed on 6/7/2000, (10) U.S. patent application serial no.
09/559,122, attorney docket no.
25791.23.02, filed on 4/26/2000, (11) PCT patent application serial no.
PCT/US00/18635, attorney docket no.
25791.25.02, filed on 7/9/2000, (12) PCT patent application serial no.
PCT/US00/30022, attorney docket no.
25791.27.02, filed on 10/31/2000, (13) U.S. patent application serial no.
09/679,907, attorney docket no.
25791.34.02, filed on 10/5/2000, (14) PCT patent application serial no.
PCT/US00/27645, attorney docket no.
25791.36.02, filed on 10/5/2000, (15) U.S. patent application serial no.
09/679,906, attorney docket no.
25791.37.02, filed on 10/5/2000, (16) PCT patent application serial no.
PCT/LTS01/19014, attorney docket no.
25791.38.02, filed on 6/12/2001, (17) PCT patent application serial no.
PCT/USO1/41446, attorney docket no.
25791.45.02, filed on 7/28/2001, (18) PCT patent application serial no.
PCT/CJSO1/23815, attorney docket no.
25791.46.02, filed on 7/27/2001, (19) PCT patent application serial no.
PCT/USO1/28960, attorney docket no.
25791.47.02, filed on 9/17/2001, (20) U.S. provisional patent application
serial no. 60/237,334, attorney docket
no. 25791.48, filed on 10/2/2000, (21) U.S. provisional patent application
serial no. 60/270,007, attorney docket
no. 25791.50, filed on 2/20/2001; (22) U.S. provisional patent application
serial no. 601262,434, attorney docket
no. 25791.51, filed on 1/17/2001; (23) U.S, provisional patent application
serial no. 60/259,486, attorney docket
no. 25791.52, filed on 1/3/2001; (24) U.S. provisional patent application
serial no. 60/303,740, attorney docket
no. 25791.61, filed on 7/6/2001; (25) U.S. provisional patent application
serial no. 60/313,453, attorney docket
no. 25791.59, filed on 8/20/2001; (26) PCT patent application serial no.
PCT/US02/24399, attorney docket no.
25791.59.02, filed on 8/1/02, (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. 60/318,021, attorney docket no.
25791.58, filed on 9/7/2001, (29) PCT patent application serial no. PCT/US ,
attorney
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docket no. 25791.58.02 filed on 8/13/02, (30) U.S. provisional patent
application serial no. 60/318,386, attorney
docket no. 25791.67.02, filed on 9/10/2001 and (31) PCT patent application
serial no.
PCT/US , attorney docket no. 25791.67.03, filed on 8/14/02, the disclosures of
which are
incorporated herein by reference.
Background of the Invention
This invention relates generally to wellbore casings, and in particular to
wellbore casings that are
formed using expandable tubing.
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.
The present invention is directed to overcoming one or more of the limitations
of the existing
procedures for forming new sections of casing in a wellbore.
Summary of the Invention
According to one aspect of the present invention, a method of creating a mono-
diameter wellbore
casing in a borehole located in a subterranean formation including a
preexisting wellbore casing is provided that
includes installing a tubular liner and a first expansion cone in the
borehole, injecting a fluidic material into the
borehole, pressurizing a portion of an interior region of the tubular liner
below the first expansion cone, radially
expanding at least a portion of the tubular liner in the borehole by extruding
at least a portion of the tubular liner
off of the first expansion cone, radially expanding an overlap between the
preexisting wellbore casing and the
tubular liner, and radially expanding the portion of the tubular liner that
does not overlap with the preexisting
wellbore casing using a second expansion cone.
According to another aspect of the present invention, a system for creating a
mono-diameter wellbore
casing in a borehole located in a subterranean formation including a
preexisting wellbore casing is provided that
includes means for installing a tubular liner and a first expansion cone in
the borehole, means for injecting a
fluidic material into the borehole, means for pressurizing a portion of an
interior region of the tubular liner below
the first expansion cone, means for radially expanding at least a portion of
the tubular liner in the borehole by
extruding at least a portion of the tubular liner off of the first expansion
cone, means for radially expanding an
overlap between the preexisting wellbore casing and the tubular liner, and
means for radially expanding the
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portion of the tubular liner that does not overlap with the preexisting
wellbore casing using a second expansion
cone.
According to another aspect of the present invention, a method of creating a
tubular structure having a
substantially constant inside diameter is provided that includes installing a
first tubular member and a first
expansion cone within a second tubular member, injecting a fluidic material
into the second tubular member,
pressurizing a portion of an interior region of the first tubular member below
the first expansion cone, radially
expanding at least a portion of the first tubular member in the second tubular
member by extruding at least a
portion of the first tubular member off of the first expansion cone, radially
expanding an overlap between the
first and second tubular members, and radially expanding the portion of the
first tubular member that does not
overlap with the second tubular member using a second expansion cone.
According to another aspect of the present invention, a system for creating a
tubular structure having a
substantially constant inside diameter is provided that includes means for
installing a first tubular member and a
first expansion cone within a second tubular member, means for injecting a
fluidic material into the second
tubular member, means for pressurizing a portion of an interior region of the
first tubular member below the first
expansion cone, means for radially expanding at least a portion of the first
tubular member in the second tubular
member by extruding at least a portion of the first tubular member off of the
first expansion cone, means for
radially expanding an overlap between the first and second tubular members,
and means for radially expanding
the portion of the first tubular member that does not overlap with the second
tubular member using a second
expansion cone.
According to another aspect of the present invention, an apparatus is provided
that includes a
subterranean formation including a borehole, a wellbore casing coupled to the
borehole, and a tubular liner
overlappingly coupled to the wellbore casing, wherein the inside diameter of
the portion of the wellbore casing
that does not overlap with the tubular liner is substantially equal to the
inside diameter of the tubular liner, and
wherein the tubular liner is coupled to the wellbore casing by a method
including installing the tubular liner and
a first expansion cone in the borehole, injecting a fluidic material into the
borehole, pressurizing a portion of an
interior region of the tubular liner below the first expansion cone, radially
expanding at least a portion of the
tubular liner in the borehole by extruding at least a portion of the tubular
liner off of the first expansion cone,
radially expanding an overlap between the wellbore casing and the tubular
liner, and radially expanding the
portion of the tubular liner that does not overlap with the wellbore casing
using a second expansion cone.
According to another aspect of the present invention, an apparatus is provided
that includes a first
tubular member, and a second tubular member overlappingly coupled to the first
tubular member, wherein the
inside diameter of the portion of the first tubular member that does not
overlap with the second tubular member
is substantially equal to the inside diameter of the second tubular member,
and wherein the second tubular
member is coupled to the first tubular member by a method that includes
installing the second tubular member
and a first expansion cone in the first tubular member, injecting a fluidic
material into the first tubular member,
pressurizing a portion of an interior region of the second tubular member
below the first expansion cone, radially
expanding at least a portion of the second tubular member in the first tubular
member by extruding at least a
portion of the tubular liner off of the first expansion cone, radially
expanding an overlap between the first and
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second tubular members, and radially expanding the portion of the second
tubular member that does not overlap
with the fn-st tubular member using a second expansion cone.
Brief Description of the Drawings
FIG. 1 is a fragmentary cross-sectional view illustrating the drilling of a
new section of a well borehole
in a borehole including a preexisting section of wellbore casing.
FIG. 2 is a fragmentary cross-sectional view illustrating the placement of an
embodiment of an
apparatus for creating a casing within the new section of the well borehole of
FIG. 1.
FIG. 3 is a fragmentary cross-sectional view illustrating the injection of a
hardenable fluidic sealing
material into the new section of the well borehole of FIG. 2.
FIG. 4 is a fragmentary cross-sectional view illustrating the injection of a
fluidic material into the new
section of the well borehole of FIG. 3.
FIG. 5 is a fragmentary cross-sectional view illustrating the drilling out of
the cured hardenable fluidic
sealing material and the shoe from the new section of the well borehole of
FIG. 4.
FIG. 6 is a cross-sectional view of the well borehole of FIG. 5 following the
drilling out of the shoe.
FIG. 7 is fragmentary cross-sectional illustration of the well borehole of
FIG. 6 after positioning a
shaped charge within the overlap between the expandable tubular member and the
preexisting wellbore casing.
FIG. 8 is a cross-sectional illustration of the well borehole of FIG. 7 after
detonating the shaped charge
to plastically deform and radially expand the overlap between the expandable
tubular member and the
preexisting wellbore casing.
FIG. 9 is a fragmentary cross-sectional view of the placement and actuation of
an expansion cone within
the well borehole of FIG. 8 to form a mono-diameter wellbore casing.
FIG. 10 is a cross-sectional illustration of the well borehole of FIG. 9
following the formation of a
mono-diameter wellbore casing.
FIG. 11 is a cross-sectional illustration of the well borehole of FIG. 10
following the repeated operation
of the methods of FIGS. 1-10 in order to form a mono-diameter wellbore casing
including a plurality of
overlapping wellbore casings.
FIG. 12 is a fragmentary cross-sectional illustration of the placement of an
alternative embodiment of
an apparatus for forming a mono-diameter wellbore casing into the well
borehole of FIG. 8.
FIG. 13 is a cross-sectional illustration of the well borehole of FIG. 12
following the formation of a
mono-diameter wellbore casing.
FIG. 14 is a fragmentary cross-sectional illustration of the placement of an
alternative embodiment of
an apparatus for forming a mono-diameter wellbore casing into the well
borehole of FIG. 8.
FIG. 15 is a fragmentary cross-sectional illustration of the well borehole of
FIG. 14 during the injection
of pressurized fluids into the well borehole.
FIG. 16 is a fragmentary cross-sectional illustration of the well borehole of
FIG. 15 during the
formation of the mono-diameter wellbore casing.
FIG. 17 is a fragmentary cross-sectional illustration of the well borehole of
FIG. 16 following the
formation of the mono-diameter wellbore casing.
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Detailed Description of the Illustrative Embodiments
Referring initially to FIGS. 1-10, an embodiment of an apparatus and method
for forming a mono-
diameter wellbore casing within a subterranean formation will now be
described. As illustrated in Fig. I, a
wellbore 100 is positioned in a subterranean formation 105. The wellbore 100
includes a pre-existing cased
section 110 having pre-existing wellbore casing 115 and an annular outer layer
120 of a fluidic sealing material
such as, for example, cement. The wellbore 100 may be positioned in any
orientation from vertical to horizontal.
In several alternative embodiments, the pre-existing cased section 110 does
not include the annular outer layer
120.
In order to extend the wellbore 100 into the subterranean formation 105, a
drill string 125 is used in a
well known manner to drill out material from the subterranean formation 105 to
form a new wellbore section
130.
As illustrated in FIG. 2, an apparatus 200 for forming a wellbore casing in a
subterranean formation is
then positioned in the new section 130 of the wellbore 100 that includes
tubular expansion cone 205 having a
fluid passage 205a that supports an expandable tubular member 210 that
includes a lower portion 210a, an
intermediate portion 210b, an upper portion 210c, and an upper end portion
210d.
The tubular expansion cone 205 may be any number of conventional commercially
available expansion
cones. In several alternative embodiments, the tubular expansion cone 205 may
be controllably expandable in
the radial direction, for example, as disclosed in U.S. patent nos. 5,348,095,
and/or 6,012,523, the disclosures of
which are incorporated herein by reference.
The expandable tubular member 210 may be fabricated from any number of
conventional commercially
available materials such as, for example, Oilfield Country Tubular Goods
(OCTG), 13 chromium steel
tubing/casing, or plastic tubing/casing. In an exemplary embodiment, the
expandable tubular member 210 is
fabricated from OCTG in order to maximize strength after expansion. In several
alternative embodiments, the
expandable tubular member 210 may be solid and/or slotted. In an exemplary
embodiment, the length of the
expandable tubular member 210 is limited to minimize the possibility of
buckling. For typical expandable
tubular member 210 materials, the length of the expandable tubular member 210
is preferably limited to between
about 40 to 20,000 feet in length.
The lower portion 210a of the expandable tubular member 210 preferably has a
larger inside diameter
than the upper portion 210c of the expandable tubular member. In an exemplary
embodiment, the wall thickness
of the intermediate portion 210b of the expandable tubular member 210 is less
than the wall thickness of the
upper portion 21 Oc of the expandable tubular member in order to faciliate the
initiation of the radial expansion
process. In an exemplary embodiment, the upper end portion 210d of the
expandable tubular member 210 is
slotted, perforated, or otherwise modified to catch or slow down the expansion
cone 205 when it completes the
extrusion of expandable tubular member 210.
A shoe 215 is coupled to the lower portion 210a of the expandable tubular
member. The shoe 215
includes a valveable fluid passage 220 that is preferably adapted to receive a
plug, dart, or other similar element
for controllably sealing the fluid passage 220. In this manner, the fluid
passage 220 may be optimally sealed off
by introducing a plug, dart and/or ball sealing elements into the fluid
passage 240.
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The shoe 215 may be any number of conventional commercially available shoes
such as, for example,
Super Seal II float shoe, Super Seal II Down-Jet float shoe or a guide shoe
with a sealing sleeve for a latch down
plug modified in accordance with the teachings of the present disclosure. In
an exemplary embodiment, the shoe
215 is an aluminum down jet guide shoe with a sealing sleeve for a latch-down
plug available from Halliburton
Energy Services in Dallas, TX, modified in accordance with the teachings of
the present disclosure, in order to
optimally guide the expandable tubular member 210 in the wellbore, optimally
provide an adequate seal between
the interior and exterior diameters of the overlapping joint between the
tubular members, and to optimally allow
the complete drill out of the shoe and plug after the completion of the
cementing and expansion operations.
In an exemplary embodiment, the shoe 215 further includes one or more through
and side outlet ports in
fluidic communication with the fluid passage 220. 1n this manner, the shoe 215
optimally injects hardenable
fluidic sealing material into the region outside the shoe 215 and expandable
tubular member 210.
A support member 225 having fluid passages 225a and 225b is coupled to the
expansion cone 205 for
supporting the apparatus 200. The fluid passage 225a is preferably fluidicly
coupled to the fluid passage 205a.
In this manner, fluidic materials may be conveyed to and from a region 230
below the expansion cone 205 and
above the bottom of the shoe 215. The fluid passage 225b is preferably
fluidicly coupled to the fluid passage
225a and includes a conventional control valve. In this manner, during
placement of the apparatus 200 within
the wellbore 100, surge pressures can be relieved by the fluid passage 225b.
In an exemplary embodiment, the
support member 225 further includes one or more conventional centralizers (not
illustrated) to help stabilize the
apparatus 200.
During placement of the apparatus 200 within the wellbore 100, the fluid
passage 225a is preferably
selected to transport materials such as, for example, drilling mud or
formation fluids at flow rates and pressures
ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to
minimize drag on the tubular
member being run and to minimize surge pressures exerted on the wellbore 130
which could cause a loss of
wellbore fluids and lead to hole collapse. During placement of the apparatus
200 within the wellbore 100, the
2$ fluid passage 225b is preferably selected to convey fluidic materials at
flow rates and pressures ranging from
about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to reduce the drag
on the apparatus 200 during
insertion into the new section 130 of the wellbore 100 and to minimize surge
pressures on the new wellbore
section 130.
A lower cup seal 235 is coupled to and supported by the support member 225.
The lower cup seal 235
prevents foreign materials from entering the interior region of the expandable
tubular member 210 adjacent to
the expansion cone 205. The lower cup seal 235 may be any number of
conventional commercially available
cup seals such as, for example, TP cups, or Selective Injection Packer (SIP)
cups modified in accordance with
the teachings of the present disclosure. In an exemplary embodiment, the lower
cup seal 235 is a SIP cup seal,
available from Halliburton Energy Services in Dallas, TX in order to optimally
block foreign material and
contain a body of lubricant.
The upper cup seal 240 is coupled to and supported by the support member 225.
The upper cup seal
240 prevents foreign materials from entering the interior region of the
expandable tubular member 210. The
upper cup seal 240 may be any number of conventional commercially available
cup seals such as, for example,
TP cups or SIP cups modified in accordance with the teachings of the present
disclosure. In an exemplary
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embodiment, the upper cup seal 240 is a SIP cup, available from Halliburton
Energy Services in Dallas, TX in
order to optimally block the entry of foreign materials and contain a body of
lubricant.
One or more sealing members 245 are coupled to and supported by the exterior
surface of the upper end
portion 210d of the expandable tubular member 210. The seal members 245
preferably provide an overlapping
joint between the lower end portion 115a of the casing 115 and the portion 260
of the expandable tubular
member 210 to be fluidicly sealed. The sealing members 245 may be any number
of conventional commercially
available seals such as, for example, lead, rubber, Teflon, or epoxy seals
modified in accordance with the
teachings of the present disclosure. In an exemplary embodiment, the sealing
members 245 are molded from
Stratalock epoxy available from Halliburton Energy Services in Dallas, TX in
order to optimally provide a load
bearing interference fit between the upper end portion 21 Od of the expandable
tubular member 210 and the lower
end portion 115a of the existing casing 115.
In an exemplary embodiment, the sealing members 245 are selected to optimally
provide a sufficient
frictional force to support the expanded tubular member 210 from the existing
casing 115. In an exemplary
embodiment, the frictional force optimally provided by the sealing members 245
ranges from about 1,000 to
1,000,000 lbf in order to optimally support the expanded tubular member 210.
In an exemplary embodiment, a quantity of lubricant 250 is provided in the
annular region above the
expansion cone 205 within the interior of the expandable tubular member 210.
In this manner, the extrusion of
the expandable tubular member 210 off of the expansion cone 205 is
facilitated. The lubricant 250 may be any
number of conventional commercially available lubricants such as, for example,
Lubriplate, chlorine based
2~ lubricants, oil based lubricants or Climax 1500 Antisieze (3100). In an
exemplary embodiment, the lubricant
250 is Climax 1500 Antisieze (3100) available from Climax Lubricants and
Equipment Co. in Houston, TX in
order to optimally provide optimum lubrication to faciliate the expansion
process.
In an exemplary embodiment, the support member 225 is thoroughly cleaned prior
to assembly to the
remaining portions of the apparatus 200. In this manner, the introduction of
foreign material into the apparatus
200 is minimized. This minimizes the possibility of foreign material clogging
the various flow passages and
valves of the apparatus 200.
In an exemplary embodiment, before or after positioning the apparatus 200
within the new section 130
of the wellbore 100, a couple of wellbore volumes are circulated in order to
ensure that no foreign materials are
located within the wellbore 100 that might clog up the various flow passages
and valves of the apparatus 200 and
to ensure that no foreign material interferes with the expansion process.
As illustrated in FIG. 2, in an exemplary embodiment, during placement of the
apparatus 200 within the
wellbore 100, fluidic materials 255 within the wellbore that are displaced by
the apparatus are conveyed through
the fluid passages 220, 205a, 225a, and 225b. In this manner, surge pressures
created by the placement of the
apparatus within the wellbore 100 are reduced.
As illustrated in FIG. 3, the fluid passage 225b is then closed and a
hardenable fluidic sealing material
305 is then pumped from a surface location into the fluid passages 225a and
205a. The material 305 then passes
from the fluid passage 205a into the interior region 230 of the expandable
tubular member 210 below the
expansion cone 205. The material 305 then passes from the interior region 230
into the fluid passage 220. The
material 305 then exits the apparatus 200 and fills an annular region 310
between the exterior of the expandable
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tubular member 210 and the interior wall of the new section 130 of the
wellbore 100. Continued pumping of the
material 305 causes the material 305 to fill up at least a portion of the
annular region 310.
The material 305 is preferably pumped into the annular region 310 at pressures
and flow rates ranging,
for example, from about 0 to 5000 psi and 0 to 1,500 gallons/min,
respectively. The optimum flow rate and
$ operating pressures vary as a function of the casing and wellbore sizes,
wellbore section length, available
pumping equipment, and fluid properties of the fluidic material being pumped.
The optimum flow rate and
operating pressure are preferably determined using conventional empirical
methods.
The hardenable fluidic sealing material 305 may be any number of conventional
commercially available
hardenable fluidic sealing materials such as, for example, slag mix, cement or
epoxy. In an exemplary
embodiment, the hardenable fluidic sealing material 305 is a blended cement
prepared specifically for the
particular well section being drilled from Halliburton Energy Services in
Dallas, TX in order to provide optimal
support for expandable tubular member 210 while also maintaining optimum flow
characteristics so as to
minimize difficulties during the displacement of cement in the annular region
315. The optimum blend of the
blended cement is preferably determined using conventional empirical methods.
In several alternative
embodiments, the hardenable fluidic sealing material 305 is compressible
before, during, or after curing.
The annular region 310 preferably is filled with the material 305 in
sufficient quantities to ensure that,
upon radial expansion of the expandable tubular member 210, the annular region
310 of the new section 130 of
the wellbore 100 will be filled with the material 305.
In an alternative embodiment, the injection of the material 305 into the
annular region 310 is omitted.
As illustrated in FIG. 4, once the annular region 310 has been adequately
filled with the material 305, a
plug 405, or other similar device, is introduced into the fluid passage 220,
thereby fluidicly isolating the interior
region 230 from the annular region 310. In an exemplary embodiment, a non-
hardenable fluidic material 315 is
then pumped into the interior region 230 causing the interior region to
pressurize. In this manner, the interior
region 230 of the expanded tubular member 210 will not contain significant
amounts of cured material 305. This
2$ also reduces and simplifies the cost of the entire process. Alternatively,
the material 305 may be used during this
phase of the process.
Once the interior region 230 becomes sufficiently pressurized, the expandable
tubular member 210 is
preferably plastically deformed, radially expanded, and extruded off of the
expansion cone 205. During the
extrusion process, the expansion cone 205 may be raised out of the expanded
portion of the expandable tubular
member 210. In an exemplary embodiment, during the extrusion process, the
expansion cone 205 is raised at
approximately the same rate as the expandable tubular member 210 is expanded
in order to keep the expandable
tubular member 210 stationary relative to the new wellbore section 130. In an
alternative preferred embodiment,
the extrusion process is commenced with the expandable tubular member 210
positioned above the bottom of the
new wellbore section 130, keeping the expansion cone 205 stationary, and
allowing the expandable tubular
member 210 to extrude off of the expansion cone 205 and into the new wellbore
section 130 under the force of
gravity and the operating pressure of the interior region 230.
The plug 405 is preferably placed into the fluid passage 220 by introducing
the plug 405 into the fluid
passage 225a at a surface location in a conventional manner. The plug 405
preferably acts to fluidicly isolate the
hardenable fluidic sealing material 305 from the non hardenable fluidic
material 315.
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The plug 405 may be any number of conventional commercially available devices
from plugging a fluid
passage such as, for example, Multiple Stage Cementer (MSC) latch-down plug,
Omega latch-down plug or
three-wiper latch-down plug modified in accordance with the teachings of the
present disclosure. In an
exemplary embodiment, the plug 405 is a MSC latch-down plug available from
Halliburton Energy Services in
Dallas, TX.
After placement of the plug 405 in the fluid passage 220, the non hardenable
fluidic material 315 is
preferably pumped into the interior region 310 at pressures and flow rates
ranging, for example, from
approximately 400 to 10,000 psi and 30 to 4,000 gallons/min. In this manner,
the amount of hardenable fluidic
sealing material within the interior 230 of the expandable tubular member 210
is minimized. In an exemplary
embodiment, after placement of the plug 405 in the fluid passage 220, the non
hardenable material 315 is
preferably pumped into the interior region 230 at pressures and flow rates
ranging from approximately 500 to
9,000 psi and 40 to 3,000 gallons/min in order to maximize the extrusion
speed.
In an exemplary embodiment, the apparatus 200 is adapted to minimize tensile,
burst, and friction
effects upon the expandable tubular member 210 during the expansion process.
These effects will be depend
upon the geometry of the expansion cone 205, the material composition of the
expandable tubular member 210
and expansion cone 205, the inner diameter of the expandable tubular member,
the wall thickness of the
expandable tubular member, the type of lubricant, and the yield strength of
the expandable tubular member. In
general, the thicker the wall thickness, the smaller the inner diameter, and
the greater the yield strength of the
expandable tubular member 210, then the greater the operating pressures
required to extrude the expandable
tubular member 210 off of the expansion cone 205.
In an exemplary embodiment, the extrusion of the expandable tubular member off
of the expansion
cone 205 will begin when the pressure of the interior region 230 reaches, for
example, approximately 500 to
9,000 psi.
During the extrusion process, the expansion cone 205 may be raised out of the
expanded portion of the
expandable tubular member 210 at rates ranging, for example, from about 0 to 5
ft/sec. In an exemplary
embodiment, during the extrusion process, the expansion cone 205 is raised out
of the expanded portion of the
expandable tubular member 210 at rates ranging from about 0 to 2 ft/sec in
order to minimize the time required
for the expansion process while also permitting easy control of the expansion
process.
When the upper end portion 210d of the expandable tubular member 210 is
extruded off of the
expansion cone 205, the outer surface of the upper end portion 210d of the
expandable tubular member 210 will
preferably contact the interior surface of the lower end portion 115a of the
wellbore casing 115 to form an fluid
tight overlapping joint. The contact pressure of the overlapping joint may
range, for example, from
approximately 50 to 20,000 psi. In an exemplary embodiment, the contact
pressure of the overlapping joint
ranges from approximately 400 to 10,000 psi in order to provide optimum
pressure to activate the annular
sealing members 245 and optimally provide resistance to axial motion to
accommodate typical tensile and
compressive loads.
The overlapping joint between the pre-existing wellbore casing 115 and the
radially expanded
expandable tubular member 210 preferably provides a gaseous and fluidic seal.
In a particularly preferred
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embodiment, the sealing members 245 optimally provide a fluidic and gaseous
seal in the overlapping joint. In
an alternative embodiment, the sealing members 245 are omitted.
In an exemplary embodiment, the operating pressure and flow rate of the non-
hardenable fluidic
material 315 is controllably ramped down when the expansion cone 205 reaches
the upper end portion 210d of
the expandable tubular member 210. In this manner, the sudden release of
pressure caused by the complete
extrusion of the expandable tubular member 210 off of the expansion cone 205
can be minimized. In an
exemplary embodiment, the operating pressure is reduced in a substantially
linear fashion from 100% to about
10% during the end of the extrusion process beginning when the expansion cone
205 is within about 5 feet from
completion of the extrusion process.
Alternatively, or in combination, a shock absorber is provided in the support
member 225 in order to
absorb the shock caused by the sudden release of pressure. The shock absorber
may, for example, be any
conventional commercially available shock absorber adapted for use in wellbore
operations.
Alternatively, or in combination, an expansion cone catching structure is
provided in the upper end
portion 210d of the expandable tubular member 210 in order to catch or at
least decelerate the expansion cone
205.
Once the extrusion process is completed, the expansion cone 205 is removed
from the wellbore 100. In
an exemplary embodiment, either before or after the removal of the expansion
cone 205, the integrity of the
fluidic seal of the overlapping joint between the upper end portion 210d of
the expandable tubular member 210
and the lower end portion 115a of the preexisting wellbore casing 115 is
tested using conventional methods.
In an exemplary embodiment, if the fluidic seal of the overlapping joint
between the upper end portion
210d of the expandable tubular member 210 and the lower end portion 115a of
the casing 115 is satisfactory,
then any uncured portion of the material 305 within the expanded expandable
tubular member 210 is then
removed in a conventional manner such as, for example, circulating the uncured
material out of the interior of
the expanded tubular member 210. The expansion cone 205 is then pulled out of
the wellbore section 130 and a
drill bit or mill is used in combination with a conventional drilling assembly
505 to drill out any hardened
material 305 within the expandable tubular member 210. In an exemplary
embodiment, the material 305 within
the annular region 310 is then allowed to fully cure.
As illustrated in Fig. 5, preferably any remaining cured material 305 within
the interior of the expanded
tubular member 210 is then removed in a conventional manner using a
conventional drill string 505. The
resulting new section of casing 510 preferably includes the expanded tubular
member 210 and an outer annular
layer 515 of the cured material 305.
As illustrated in FIG. 6, the bottom portion of the apparatus 200 including
the shoe 215 and dart 405
may then be removed by drilling out the shoe 215 and dart 405 using
conventional drilling methods.
As illustrated in FIG. 7, an apparatus 600 for radially expanding and
plastically deforming the overlap
between the lower portion of the preexisting wellbore casing 115 and the upper
portion 210d of the expandable
tubular member 210 may then be positioned within the borehole 110 that
includes a shaped charge 605 that is
coupled to an end of a tubular member 610. In an exemplary embodiment, the
shaped charge 605 is positioned
within the overlap between the lower portion of the preexisting wellbore
casing 115 and the upper portion 21 Od
of the expandable tubular member 210.
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As illustrated in FIG. 8, the shaped charge 605 is then detonated in a
conventional manner to plastically
deform and radially expand the overlap between the lower portion of the
preexisting wellbore casing 115 and the
upper portion 210d of the expanded tubular member 210. As a result, the inside
diameter of the upper portion
210d of the expanded tubular member 210 is substantially equal to the inside
diameter of the portion of the
preexisting wellbore casing 115 that does not overlap with the upper portion
of the expanded tubular member.
In several alternative embodiments, one or more conventional devices for
generating impulsive radially directed
forces may be substituted for, or used in combination with, the shaped charge
605.
As illustrated in FIG. 9, an apparatus 700 for forming a mono-diameter
wellbore casing is then
positioned within the wellbore casing 115 proximate upper end 210d of the
expandable tubular member 210 that
includes a tubular expansion cone 705 coupled to an end of a tubular support
member 710. In an exemplary
embodiment, the outside diameter of the tubular expansion cone 705 is
substantially equal to the inside diameter
of the wellbore casing 115. The tubular expansion cone 705 and the tubular
support member 710 together define
a fluid passage 715 for conveying ftuidic materials 720 out of the wellbore
100 that are displaced by the
placement and operation of the tubular expansion cone 705.
The tubular expansion cone 705 is then driven downward using the support
member 710 in order to
radially expand and plastically deform the portion of the expandable tubular
member 210 that does not overlap
with the wellbore casing 115. In this manner, as illustrated in FIG. 10, a
mono-diameter wellbore casing is
formed that includes the overlapping wellbore casings 115 and 210. In several
alternative embodiments, the
secondary radial expansion process illustrated in FIGS. 9 and 10 is performed
before, during, or after the
material 515 fully cures. In several alternative embodiments, a conventional
expansion device including rollers
may be substituted for, or used in combination with, the apparatus 700. In an
exemplary embodiment, the
downward displacement of the tubular expansion cone 705 also at least
partially radially expands and plastically
deforms the portions of the pre-existing wellbore casing 115 and the upper
portion 210d of the expandable
tubular member that overlap with one another,
More generally, as illustrated in FIG. 1 l, the method of FIGS. 1-10 is
repeatedly performed in order to
provide a mono-diameter wellbore casing that includes overlapping wellbore
casings 115 and 210a-210e. The
wellbore casings 115, and 210a-210e preferably include outer annular layers of
fluidic sealing material. In this
manner, a mono-diameter wellbore casing may be formed within the subterranean
formation that extends for tens
of thousands of feet. More generally still, the teachings of FIGS. 1-11 may be
used to form a mono-diameter
wellbore casing, a pipeline, a structural support, or a tunnel within a
subterranean formation at any orientation
from the vertical to the horizontal.
In an exemplary embodiment, the formation of the mono-diameter wellbore
casing, as illustrated in
FIGS. 1-I 1, is further provided as disclosed in one or more of 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, (5) PCT
patent application serial no.
PCT/USO1/04753, attorney docket no. 25791.10.02, filed on 2/14/2001, (6) U.S.
patent application serial no.
09/523,460, attorney docket no. 25791.11.02, filed on 3/10/2000, (7) U.S.
patent application serial no.
11
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09/512,895, attorney docket no. 25791.12.02, filed on 2/24/2000, (8) U.S.
patent application serial no.
09/511,941, attorney docket no. 25791.16.02, filed on 2/24/2000, (9) U.S.
patent application serial no.
09/588,946, attorney docket no. 25791.17.02, filed on 6/7/2000, (10) U.S.
patent application serial no.
09/559,122, attorney docket no. 25791.23.02, filed on 4/26/2000, (I 1) PCT
patent application serial no.
PCT/US00/18635, attorney docket no. 25791.25.02, filed on 7/9/2000, (12) PCT
patent application serial no.
PCT/LJS00/30022, attorney docket no. 25791.27.02, filed on 10/31/2000, (13)
U.S. patent application serial no.
09/679,907, attorney docket no. 25791.34.02, filed on 10/5/2000, (14) PCT
patent application serial no.
PCT/LJS00/27645, attorney docket no. 25791.36.02, filed on 10/5/2000, (15)
U.S. patent application serial no.
09/679,906, attorney docket no. 25791.37.02, filed on 10/5/2000, (16) PCT
patent application serial no.
PCT/USO1/19014, attorney docket no. 25791.38.02, filed on 6/12/2001, (17) PCT
patent application serial no.
PCT/USO1/41446, attorney docket no. 25791.45.02, filed on 7/28/2001, (18) PCT
patent application serial no.
PCT/LJSOI/23815, attorney docket no. 25791.46.02, filed on 7/27/2001, (19) PCT
patent application serial no.
PCT/USO1/28960, attorney docket no. 25791.47.02, filed on 9/17/2001, (20) U.S.
provisional patent application
serial no. 60/237,334, attorney docket no. 25791.48, filed on 10/2/2000, (21)
U.S. provisional patent application
serial no. 60/270,007, attorney docket no. 25791.50, filed on 2/20/2001; (22)
U.S. provisional patent application
serial no. 60/262,434, attorney docket no. 25791.51, filed on 1/17/2001; (23)
U.S, provisional patent application
serial no. 60/259,486, attorney docket no. 25791.52, filed on 1/3/2001; (24)
U.S. provisional patent application
serial no. 60/303,740, attorney docket no. 25791.61, filed on 7/6/2001; (25)
U.S. provisional patent application
serial no. 60/313,453, attorney docket no. 25791.59, filed on 8/20/2001; (26)
PCT patent application serial no.
PCT/iJS02/24399, attorney docket no. 25791.59.02, filed on 8/1/02, (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. 60/318,021, attorney docket no. 25791.58, filed on 9/7/2001, (29)
PCT patent application serial no.
PCT/US , attorney docket no. 25791.58.02 filed on 8/13/02, (30) U.S.
provisional patent
application serial no. 60/318,386, attorney docket no. 25791.67.02, filed on
9/10/2001 and (31) PCT patent
application serial no. PCT/US , attorney docket no. 25791.67.03, filed on
8/14/02, the
disclosures of which are incorporated herein by reference.
In an alternative embodiment, the fluid passage 220 in the shoe 215 is
omitted. In this manner, the
pressurization of the region 230 is simplified. In an alternative embodiment,
the annular body 515 of the fluidic
sealing material is formed using conventional methods of injecting a
hardenable fluidic sealing material into the
annular region 310.
In an alternative embodiment of the apparatus 700, the fluid passage 715 is
omitted. In this manner, in
an exemplary embodiment, the region of the wellbore 100 below the expansion
cone 705 is pressurized and one
or more regions of the subterranean formation 105 are fractured to enhance the
oil and/or gas recovery process.
Referring to FIGS. 12-13, in an alternative embodiment, an apparatus 800 for
forming a mono-diameter
wellbore casing is positioned within the wellbore casing I 15 that includes a
tubular expansion cone 805 that
defines a fluid passage 805a that is coupled to a support member 810.
The tubular expansion cone 805 preferably further includes a conical outer
surface 805b for radially
expanding and plastically deforming the portion of the expandable tubular
member 210 that does not overlap
with the wellbore casing 115. In an exemplary embodiment, the outside diameter
of the tubular expansion cone
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805 is substantially equal to the inside diameter of the portion of the pre-
existing wellbore casing 115 that does
not overlap with the expandable tubular member 210.
The support member 810 is coupled to a slip joint 815, and the slip joint is
coupled to a support
member 820. As will be recognized by persons having ordinary skill in the art,
a slip joint permits relative
movement between objects. Thus, in this manner, the expansion cone 805 and
support member 810 may be
displaced in the longitudinal direction relative to the support member 820. In
an exemplary embodiment, the
slip joint 810 permits the expansion cone 805 and support member 810 to be
displaced in the longitudinal
direction relative to the support member 820 for a distance greater than or
equal to the axial length of the
expandable tubular member 210. In this manner, the expansion cone 805 may be
used to plastically deform and
radially expand the portion of the expandable tubular member 210 that does not
overlap with the pre-existing
wellbore casing 115 without having to reposition the support member 820.
The slip joint 815 may be any number of conventional commercially available
slip joints that include a
fluid passage for conveying fluidic materials through the slip joint. In an
exemplary embodiment, the slip joint
815 is a pumper sub commercially available from Bowen Oil Tools in order to
optimally provide elongation of
the drill string.
The support member 810, slip joint 815, and support member 820 further include
fluid passages 810a,
815a, and 820a, respectively, that are fluidicly coupled to the fluid passage
805a. During operation, the fluid
passages 805a, 810a, 815a, and 820a preferably permit fluidic materials 825
displaced by the expansion cone
805 to be conveyed to a location above the apparatus 800. In this manner,
operating pressures within the
subterranean formation 105 below the expansion cone are minimized.
The support member 820 further preferably includes a fluid passage 820b that
permits fluidic materials
830 to be conveyed into an annular region 835 surrounding the support member
810, the slip joint 815, and the
support member 820 and bounded by the expansion cone 805 and a conventional
packer 840 that is coupled to
the support member 820. In this manner, the annular region 835 may be
pressurized by the injection of the fluids
830 thereby causing the expansion cone 805 to be displaced in the longitudinal
direction relative to the support
member 820 to thereby plastically deform and radially expand the portion of
the expandable tubular member 210
that does not overlap with the pre-existing wellbore casing 115.
During operation, as illustrated in FIG. 10, in an exemplary embodiment, the
apparatus 800 is
positioned within the preexisting casing 115 with the bottom surface of the
expansion cone 805 proximate the
top of the expandable tubular member 210. During placement of the apparatus
800 within the preexisting casing
115, fluidic materials 825 within the casing are conveyed out of the casing
through the fluid passages 805a,
810a, 815a, and 820a. In this manner, surge pressures within the wellbore 100
are minimized.
The packer 840 is then operated in a well-known manner to fluidicly isolate
the annular region 835
from the annular region above the packer. The fluidic material 830 is then
injected into the annular region 835
using the fluid passage 820b. Continued injection of the fluidic material 830
into the annular region 835
preferably pressurizes the annular region and thereby causes the expansion
cone 805 and support member 810 to
be displaced in the longitudinal direction relative to the support member 820.
As illustrated in FIG. 13, in an exemplary embodiment, the longitudinal
displacement of the expansion
cone 805 in turn plastically deforms and radially expands the portion of the
expandable tubular member 210 that
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does not overlap the pre-existing wellbore casing 115. In this manner, a mono-
diameter wellbore casing is
formed that includes the overlapping wellbore casings 115 and 210. The
apparatus 800 may then be removed
from the wellbore 100 by releasing the packer 840 from engagement with the
wellbore casing 115, and lifting the
apparatus 800 out of the wellbore 100. In an exemplary embodiment, the
downward longitudinal displacement
of the expansion cone 805 also at least partially radially expands and
plastically deforms the portions of the pre-
existing wellbore casing 115 and the upper portion 210d of the expandable
tubular member 210 that overlap
with one another.
In an alternative embodiment of the apparatus 800, the fluid passage 820b is
provided within the packer
840 in order to enhance the operation of the apparatus 800.
In an alternative embodiment of the apparatus 800, the fluid passages 805a,
810a, 815a, and 820a are
omitted. In this manner, in an exemplary embodiment, the region of the
wellbore 100 below the expansion cone
805 is pressurized and one or more regions of the subterranean formation 105
are fractured to enhance the oil
and/or gas recovery process.
Referring to FIGS. 14-17, in an alternative embodiment, an apparatus 900 is
positioned within the
wellbore casing 115 that includes an expansion cone 905 having a fluid passage
905a that is releasably coupled
to a releasable coupling 910 having fluid passage 910a.
The fluid passage 905a is preferably adapted to receive a conventional ball,
plug, or other similar
device for sealing off the fluid passage. The expansion cone 905 further
includes a conical outer surface 905b
for radially expanding and plastically deforming the portion of the expandable
tubular member 210 that does not
overlap the pre-existing wellbore casing 1 I 5. In an exemplary embodiment,
the outside diameter of the
expansion cone 905 is substantially equal to the inside diameter of the
portion of the pre-existing wellbore casing
115 that does not overlap with the upper end 210d of the expandable tubular
member 210.
The releasable coupling 910 may be any number of conventional commercially
available releasable
couplings that include a fluid passage for conveying fluidic materials through
the releasable coupling. In an
exemplary embodiment, the releasable coupling 910 is a safety joint
commercially available from Halliburton in
order to optimally release the expansion cone 905 from the support member 91 S
at a predetermined location.
A support member 915 is coupled to the releasable coupling 910 that includes a
fluid passage 915a.
The fluid passages 905a, 910a and 91 Sa are fluidicly coupled. In this manner,
fluidie materials may be conveyed
into and out of the wellbore 100.
A packer 920 is movably and sealingly coupled to the support member 915. The
packer may be any
number of conventional packers. In an exemplary embodiment, the packer 920 is
a commercially available burst
preventer (BOP) in order to optimally provide a sealing member.
During operation, as illustrated in FIG. 14, in an exemplary embodiment, the
apparatus 900 is
positioned within the preexisting casing 115 with the bottom surface of the
expansion cone 905 proximate the
3 $ top of the expandable tubular member 210. During placement of the
apparatus 900 within the preexisting casing
115, fluidic materials 925 within the casing are conveyed out of the casing
through the fluid passages 905a,
910a, and 915a. In this manner, surge pressures within the wellbore 100 are
minimized. The packer 920 is then
operated in a well-known manner to fluidicly isolate a region 930 within the
casing 1 I S between the expansion
cone 905 and the packer 920 from the region above the packer.
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In an exemplary embodiment, as illustrated in FIG. 15, the releasable coupling
910 is then released
from engagement with the expansion cone 905 and the support member 915 is
moved away from the expansion
cone. A fluidic material 935 may then be injected into the region 930 through
the fluid passages 910a and 915a.
The fluidic material 935 may then flow into the region of the wellbore 100
below the expansion cone 905
through the valveable passage 905b. Continued injection of the fluidic
material 935 may thereby pressurize and
fracture regions of the formation 105 below the expandable tubular member 210.
In this manner, the recovery of
oil and/or gas from the formation 105 may be enhanced.
In an exemplary embodiment, as illustrated in FIG. 16, a plug, ball, or other
similar valve device 940
may then be positioned in the valveable passage 905a by introducing the valve
device into the fluidic material
935. In this manner, the region 930 may be fluidicly isolated from the region
below the expansion cone 905.
Continued injection of the fluidic material 935 may then pressurize the region
930 thereby causing the expansion
cone 905 to be displaced in the longitudinal direction.
1n an exemplary embodiment, as illustrated in FIG. 17, the longitudinal
displacement of the expansion
cone 905 plastically deforms and radially expands the portion of the
expandable tubular 210 that does not
overlap with the pre-existing wellbore casing 115. In this manner, a mono-
diameter wellbore casing is formed
that includes the pre-existing wellbore casing 115 and the expandable tubular
member 210. Upon completing
the radial expansion process, the support member 915 may be moved toward the
expansion cone 905 and the
expansion cone may be re-coupled to the releasable coupling device 910. The
packer 920 may then be
decoupled from the wellbore casing 115, and the expansion cone 905 and the
remainder of the apparatus 900
may then be removed from the wellbore 100. In an exemplary embodiment, the
downward longitudinal
displacement of the expansion cone 905 also at least partially plastically
deforms and radially expands the
portions of the pre-existing wellbore casing 115 and the upper portion 210d of
the expandable tubular member
210 that overlap with one another.
In an exemplary embodiment, the displacement of the expansion cone 905 also
pressurizes the region
within the expandable tubular member 210 below the expansion cone. In this
manner, the subterranean
formation surrounding the expandable tubular member 210 may be elastically or
plastically compressed thereby
enhancing the structural properties of the formation.
A method of creating a mono-diameter wellbore casing in a borehole located in
a subterranean
formation including a preexisting wellbore casing has also been described that
includes installing a tubular liner
and a first expansion cone in the borehole, injecting a fluidic material into
the borehole, pressurizing a portion of
an interior region of the tubular liner below the first expansion cone,
radially expanding at least a portion of the
tubular liner in the borehole by extruding at least a portion of the tubular
liner off of the first expansion cone,
radially expanding an overlap between the preexisting wellbore casing and the
tubular liner, and radially
expanding the portion of the tubular liner that does not overlap with the
preexisting wellbore casing using a
second expansion cone. In an exemplary embodiment, radially expanding the
overlap between the preexisting
wellbore casing and the tubular liner includes impulsively applying outwardly
directed radial forces to the
interior of the overlap between the preexisting wellbore casing and the
tubular liner. In an exemplary
embodiment, impulsively applying outwardly directed radial forces to the
interior of the overlap between the
preexisting wellbore casing and the tubular liner includes detonating a shaped
charge within the overlap between
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the preexisting wellbore casing and the tubular liner. In an exemplary
embodiment, radially expanding the
overlap between the preexisting wellbore casing and the tubular liner further
includes displacing the second
expansion cone in a longitudinal direction, and permitting fluidic materials
displaced by the second expansion
cone to be removed. In an exemplary embodiment, displacing the second
expansion cone in a longitudinal
direction includes applying fluid pressure to the second expansion cone. In an
exemplary embodiment, radially
expanding the overlap between the tubular liner and the preexisting wellbore
casing using the second expansion
cone further includes displacing the second expansion cone in a longitudinal
direction, and compressing at least
a portion of the subterranean formation using fluid pressure. In an exemplary
embodiment, displacing the
second expansion cone in a longitudinal direction includes applying fluid
pressure to the second expansion cone.
In an exemplary embodiment, radially expanding the portion of the tubular
liner that does not overlap with the
preexisting wellbore casing using the second expansion cone includes
displacing the second expansion cone in a
longitudinal direction, and permitting fluidic materials displaced by the
second expansion cone to be removed.
In an exemplary embodiment, displacing the second expansion cone in the
longitudinal direction includes
applying fluid pressure to the second expansion cone. In an exemplary
embodiment, radially expanding the
portion of the tubular liner that does not overlap with the preexisting
wellbore casing using the second expansion
cone includes displacing the second expansion cone in a longitudinal
direction, and compressing at least a
portion of the subterranean formation using fluid pressure. In an exemplary
embodiment, displacing the second
expansion cone in the longitudinal direction includes applying fluid pressure
to the second expansion cone. In
an exemplary embodiment, the method further includes injecting a hardenable
fluidic sealing material into an
annulus between the tubular liner and the borehole.
A system for creating a mono-diameter wellbore casing in a borehole located in
a subterranean
formation including a preexisting wellbore casing has also been described that
includes means for installing a
tubular liner and a first expansion cone in the borehole, means for injecting
a fluidic material into the borehole,
means for pressurizing a portion of an interior region of the tubular liner
below the first expansion cone, means
for radially expanding at least a portion of the tubular liner in the borehole
by extruding at least a portion of the
tubular liner off of the first expansion cone, means for radially expanding an
overlap between the preexisting
wellbore casing and the tubular liner, and means for radially expanding the
portion of the tubular liner that does
not overlap with the preexisting wellbore casing using a second expansion
cone. In an exemplary embodiment,
the means for radially expanding the overlap between the preexisting wellbore
casing and the tubular liner
includes means for impulsively applying outwardly directed radial forces to
the interior of the overlap between
the preexisting wellbore casing and the tubular liner. In an exemplary
embodiment, the means for impulsively
applying outwardly directed radial forces to the interior of the overlap
between the preexisting wellbore casing
and the tubular liner includes means for detonating a shaped charge within the
overlap between the preexisting
wellbore casing and the tubular liner. In an exemplary embodiment, the means
for radially expanding the
overlap between the preexisting wellbore casing and the tubular liner further
includes displacing the second
expansion cone in a longitudinal direction, and permitting fluidic materials
displaced by the second expansion
cone to be removed. In an exemplary embodiment, the means for displacing the
second expansion cone in a
longitudinal direction includes means for applying fluid pressure to the
second expansion cone. In an exemplary
embodiment, the means for radially expanding the overlap between the tubular
liner and the preexisting wellbore
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casing using the second expansion cone further includes means for displacing
the second expansion cone in a
longitudinal direction, and means for compressing at least a portion of the
subterranean formation using fluid
pressure. In an exemplary embodiment, the means for displacing the second
expansion cone in a longitudinal
direction includes means for applying fluid pressure to the second expansion
cone. In an exemplary
embodiment, the means for radially expanding the portion of the tubular liner
that does not overlap with the
preexisting wellbore casing using the second expansion cone includes means for
displacing the second expansion
cone in a longitudinal direction, and means for permitting fluidic materials
displaced by the second expansion
cone to be removed. In an exemplary embodiment, the means for displacing the
second expansion cone in the
longitudinal direction includes means for applying fluid pressure to the
second expansion cone. In an exemplary
embodiment, the means for radially expanding the portion of the tubular liner
that does not overlap with the
preexisting wellbore casing using the second expansion cone includes means for
displacing the second expansion
cone in a longitudinal direction, and means for compressing at least a portion
of the subterranean formation
using fluid pressure. In an exemplary embodiment, the means for displacing the
second expansion cone in the
longitudinal direction includes means for applying fluid pressure to the
second expansion cone. In an exemplary
embodiment, the system further includes means for injecting a hardenable
fluidic sealing material into an annulus
between the tubular liner and the borehole.
A method of creating a tubular structure having a substantially constant
inside diameter has also been
described that includes installing a first tubular member and a first
expansion cone within a second tubular
member, injecting a fluidic material into the second tubular member,
pressurizing a portion of an interior region
of the first tubular member below the first expansion cone, radially expanding
at least a portion of the first
tubular member in the second tubular member by extruding at least a portion of
the first tubular member off of
the first expansion cone, radially expanding an overlap between the first and
second tubular members, and
radially expanding the portion of the first tubular member that does not
overlap with the second tubular member
using a second expansion cone. In an exemplary embodiment, radially expanding
the overlap between the first
and second tubular members includes impulsively applying outwardly directed
radial forces to the interior of the
overlap between the first and second tubular members. In an exemplary
embodiment, impulsively applying
outwardly directed radial forces to the interior of the overlap between the
first and second tubular members
includes detonating a shaped charge within the overlap between the first and
second tubular members. In an
exemplary embodiment, radially expanding the overlap between the first and
second tubular members further
includes displacing the second expansion cone in a longitudinal direction, and
permitting fluidic materials
displaced by the second expansion cone to be removed. In an exemplary
embodiment, displacing the second
expansion cone in a longitudinal direction includes applying fluid pressure to
the second expansion cone. In an
exemplary embodiment, radially expanding the overlap between the first and
second tubular members using the
second expansion cone further includes displacing the second expansion cone in
a longitudinal direction, and
compressing at least a portion of the subterranean formation using fluid
pressure. In an exemplary embodiment,
displacing the second expansion cone in a longitudinal direction includes
applying fluid pressure to the second
expansion cone. In an exemplary embodiment, radially expanding the portion of
the first tubular member that
does not overlap with the second tubular member using the second expansion
cone includes displacing the
second expansion cone in a longitudinal direction, and permitting fluidic
materials displaced by the second
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expansion cone to be removed. In an exemplary embodiment, displacing the
second expansion cone in the
longitudinal direction includes applying fluid pressure to the second
expansion cone.
A system for creating a tubular structure having a substantially constant
inside diameter has also been
described that includes means for installing a first tubular member and a
first expansion cone within a second
tubular member, means for injecting a fluidic material into the second tubular
member, means for pressurizing a
portion of an interior region of the first tubular member below the first
expansion cone, means for radially
expanding at least a portion of the first tubular member in the second tubular
member by extruding at least a
portion of the first tubular member off of the first expansion cone, means for
radially expanding an overlap
between the first and second tubular members, and means for radially expanding
the portion of the first tubular
member that does not overlap with the second tubular member using a second
expansion cone. In an exemplary
embodiment, the means for radially expanding the overlap between the first and
second tubular members
includes means for impulsively applying outwardly directed radial forces to
the interior of the overlap between
the first and second tubular members. In an exemplary embodiment, the means
for impulsively applying
outwardly directed radial forces to the interior of the overlap between the
first and second tubular members
includes means for detonating a shaped charge within the overlap between the
first and second tubular members.
In an exemplary embodiment, the means for radially expanding the overlap
between the first and second tubular
members further includes means for displacing the second expansion cone in a
longitudinal direction, and means
for permitting fluidic materials displaced by the second expansion cone to be
removed. In an exemplary
embodiment, the means for displacing the second expansion cone in a
longitudinal direction includes means for
applying fluid pressure to the second expansion cone. In an exemplary
embodiment, the means for radially
expanding the overlap between the first and second tubular members using the
second expansion cone further
includes means for displacing the second expansion cone in a longitudinal
direction, and means for compressing
at least a portion of the subterranean formation using fluid pressure. In an
exemplary embodiment, the means for
displacing the second expansion cone in a longitudinal direction includes
means for applying fluid pressure to
the second expansion cone. In an exemplary embodiment, the means for radially
expanding the portion of the
first tubular member that does not overlap with the second tubular member
using the second expansion cone
includes means for displacing the second expansion cone in a longitudinal
direction, and means for permitting
fluidic materials displaced by the second expansion cone to be removed. In an
exemplary embodiment, the
means for displacing the second expansion cone in the longitudinal direction
includes
means for applying fluid pressure to the second expansion cone.
An apparatus has also been described that includes a subterranean formation
including a borehole, a
wellbore casing coupled to the borehole, and a tubular liner overlappingly
coupled to the wellbore casing,
wherein the inside diameter of the portion of the wellbore casing that does
not overlap with the tubular liner is
substantially equal to the inside diameter of the tubular liner, and wherein
the tubular liner is coupled to the
wellbore casing by a method including installing the tubular liner and a first
expansion cone in the borehole,
injecting a fluidic material into the borehole, pressurizing a portion of an
interior region of the tubular liner
below the first expansion cone, radially expanding at least a portion of the
tubular liner in the borehole by
extruding at least a portion of the tubular liner off of the first expansion
cone, radially expanding an overlap
between the wellbore casing and the tubular liner, and radially expanding the
portion of the tubular liner that
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does not overlap with the wellbore casing using a second expansion cone. In an
exemplary embodiment, radially
expanding the overlap between the preexisting wellbore casing and the tubular
liner includes impulsively
applying outwardly directed radial forces to the interior of the overlap
between the wellbore casing and the
tubular liner. In an exemplary embodiment, impulsively applying outwardly
directed radial forces to the interior
of the overlap between the wellbore casing and the tubular liner includes
detonating a shaped charge within the
overlap between the wellbore casing and the tubular liner. In an exemplary
embodiment, radially expanding the
overlap between the wellbore casing and the tubular liner further includes
displacing the second expansion cone
in a longitudinal direction, and permitting fluidic materials displaced by the
second expansion cone to be
removed. In an exemplary embodiment, displacing the second expansion cone in a
longitudinal direction
includes applying fluid pressure to the second expansion cone. In an exemplary
embodiment, radially expanding
the overlap between the tubular liner and the wellbore casing using the second
expansion cone further includes
displacing the second expansion cone in a longitudinal direction, and
compressing at least a portion of the
subterranean formation using fluid pressure. In an exemplary embodiment,
displacing the second expansion
cone in a longitudinal direction includes applying fluid pressure to the
second expansion cone. In an exemplary
embodiment, radially expanding the portion of the tubular liner that does not
overlap with the wellbore casing
using the second expansion cone includes displacing the second expansion cone
in a longitudinal direction, and
permitting fluidic materials displaced by the second expansion cone to be
removed. In an exemplary
embodiment, displacing the second expansion cone in the longitudinal direction
includes applying fluid pressure
to the second expansion cone. In an exemplary embodiment, radially expanding
the portion of the tubular liner
that does not overlap with the wellbore casing using the second expansion cone
includes displacing the second
expansion cone in a longitudinal direction, and compressing at least a portion
of the subterranean formation
using fluid pressure. In an exemplary embodiment, displacing the second
expansion cone in the longitudinal
direction includes applying fluid pressure to the second expansion cone. In an
exemplary embodiment, the
apparatus further includes injecting a hardenable fluidic sealing material
into an annulus between the tubular
liner and the borehole.
An apparatus has also been described that includes a first tubular member, and
a second tubular
member overlappingly coupled to the first tubular member, wherein the inside
diameter of the portion of the first
tubular member that does not overlap with the second tubular member is
substantially equal to the inside
diameter of the second tubular member, and wherein the second tubular member
is coupled to the first tubular
member by a method that includes installing the second tubular member and a
first expansion cone in the first
tubular member, injecting a fluidic material into the first tubular member,
pressurizing a portion of an interior
region of the second tubular member below the first expansion cone, radially
expanding at least a portion of the
second tubular member in the first tubular member by extruding at least a
portion of the tubular liner off of the
first expansion cone, radially expanding an overlap between the first and
second tubular members, and radially
expanding the portion of the second tubular member that does not overlap with
the first tubular member using a
second expansion cone. In an exemplary embodiment, radially expanding the
overlap between the first and
second tubular members includes impulsively applying outwardly directed radial
forces to the interior of the
overlap between the first and second tubular members. In an exemplary
embodiment, impulsively applying
outwardly directed radial forces to the interior of the overlap between the
first and second tubular members
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includes detonating a shaped charge within the overlap between the first and
second tubular members. In an
exemplary embodiment, radially expanding the overlap between the first and
second tubular members further
includes displacing the second expansion cone in a longitudinal direction, and
permitting fluidic materials
displaced by the second expansion cone to be removed. In an exemplary
embodiment, displacing the second
expansion cone in a longitudinal direction includes applying fluid pressure to
the second expansion cone. In an
exemplary embodiment, radially expanding the overlap between the first and
second tubular members further
includes displacing the second expansion cone in a longitudinal direction, and
compressing at least a portion of
the subterranean formation using fluid pressure. In an exemplary embodiment,
displacing the second expansion
cone in a longitudinal direction includes applying fluid pressure to the
second expansion cone. In an exemplary
embodiment, radially expanding the portion of the second tubular member that
does not overlap with the first
tubular members using the second expansion cone includes displacing the second
expansion cone in a
longitudinal direction, and penmitting fluidic materials displaced by the
second expansion cone to be removed.
In an exemplary embodiment, displacing the second expansion cone in the
longitudinal direction includes
applying fluid pressure to the second expansion cone.
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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