Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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WELLHEAD
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.
Conventionally, at the surface end of the wellbore, a wellhead is formed
that typically includes a surface casing, a number of production and/or
drilling
spools, valving, and a Christmas tree. Typically the wellhead further includes
a
concentric arrangements of casings including a production casing and one or
more intermediate casings. The casings are typically supported using load
bearing slips positioned above the ground. The conventional design and
construction of wellheads is expensive and complex.
The present invention is directed to overcoming one or more of the
limitations of the existing procedures for forming wellbores and wellheads.
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Summary of the Invention
According to one aspect of the present invention, a method of forming a
wellbore casing is provided that includes installing a tubular liner and a
mandrel in the borehole, injecting fluidic material into the borehole, and
radially expanding the liner in the borehole by extruding the liner off of the
mandrel.
According to another aspect of the present invention, a method of
forming a wellbore casing is provided that includes drilling out a new section
of
the borehole adjacent to the already existing casing. A tubular liner and a
mandrel are then placed into the new section of the borehole with the tubular
liner overlapping an already existing casing. A hardenable fluidic sealing
material is injected into an annular region between the tubular liner and the
new section of the borehole. The annular region between the tubular liner and
the new section of the borehole is then fluidicly isolated from an interior
region
of the tubular liner below the mandrel. A non hardenable fluidic material is
then injected into the interior region of the tubular liner below the mandrel.
The tubular liner is extruded off of the mandrel. The overlap between the
tubular liner and the already existing casing is sealed. The tubular liner is
supported by overlap with the already existing casing. The mandrel is removed
from the borehole. The integrity of the seal of the overlap between the
tubular
liner and the already existing casing is tested. At least a portion of the
second
quantity of the hardenable fluidic sealing material is removed from the
interior
of the tubular liner. The remaining portions of the fluidic hardenable fluidic
sealing material are cured. At least a portion of cured fluidic hardenable
sealing
material within the tubular liner is removed.
According to another aspect of the present invention, an apparatus for
expanding a tubular member is provided that includes a support member, a
mandrel, a tubular member, and a shoe. The support member includes a first
fluid passage. The mandrel is coupled to the support member and includes a
second fluid passage. The tubular member is coupled to the mandrel. The shoe
is coupled to the tubular liner and includes a third fluid passage. The first,
second and third fluid passages are operably coupled.
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According to another aspect of the present invention, an apparatus for
expanding a tubular member is provided that includes a support member, an
expandable mandrel, a tubular member, a shoe, and at least one sealing
member. The support member includes a first fluid passage, a second fluid
passage, and a flow control valve coupled to the first and second fluid
passages.
The expandable mandrel is coupled to the support member and includes a third
fluid passage. The tubular member is coupled to the mandrel and includes one
or more sealing elements. The shoe is coupled to the tubular member and
includes a fourth fluid passage. The at least one sealing member is adapted to
prevent the entry of foreign material into an interior region of the tubular
member.
According to another aspect of the present invention, a method of joining
a second tubular member to a first tubular member, the first tubular member
having an inner diameter greater than an outer diameter of the second tubular
member, is provided that includes positioning a mandrel within an interior
region of the second tubular member. A portion of an interior region of the
second tubular member is pressurized and the second tubular member is
extruded off of the mandrel into engagement with the first tubular member.
According to another aspect of the present invention, a tubular liner is
provided that includes an annular member having one or more sealing
members at an end portion of the annular member, and one or more pressure
relief passages at an end portion of the annular member.
According to another aspect of the present invention, a wellbore casing is
provided that includes a tubular liner and an annular body of a cured fluidic
sealing material. The tubular liner is formed by the process of extruding the
tubular liner off of a mandrel.
According to another aspect of the present invention, a tie-back liner for
lining an existing wellbore casing is provided that includes a tubular liner
and
an annular body of cured fluidic sealing material. The tubular liner is formed
by the process of extruding the tubular liner off of a mandrel. The annular
body of a cured fluidic sealing material is coupled to the tubular liner.
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According to another aspect of the present invention, an apparatus for
expanding a tubular member is provided that includes a support member, a
mandrel, a tubular member and a shoe. The support member includes a first
fluid passage. The mandrel is coupled to the support member. The mandrel
includes a second fluid passage operably coupled to the first fluid passage,
an
interior portion, and an exterior portion. The interior portion of the mandrel
is
drillable. The tubular member is coupled to the mandrel. The shoe is coupled
to the tubular member. The shoe includes a third fluid passage operably
coupled to the second fluid passage, an interior portion, and an exterior
portion.
The interior portion of the shoe is drillable.
According to another aspect of the present invention, a wellhead is
provided that includes an outer casing and a plurality of concentric inner
casings coupled to the outer casing. Each inner casing is supported by contact
pressure between an outer surface of the inner casing and an inner surface of
the outer casing.
According to another aspect of the present invention, a wellhead is
provided that include an outer casing at least partially positioned within a
wellbore and a plurality of substantially concentric inner casings coupled to
the
interior surface of the outer casing. One or more of the inner casings are
coupled to the outer casing by expanding one or more of the inner casings into
contact with at least a portion of the interior surface of the outer casing.
According to another aspect of the present invention, a method of
forming a wellhead is provided that includes drilling a wellbore. An outer
casing is positioned at least partially within an upper portion of the
wellbore. A
first tubular member is positioned within the outer casing. At least a portion
of
the first tubular member is expanded into contact with an interior surface of
the outer casing. A second tubular member is positioned within the outer
casing and the first tubular member. At least a portion of the second tubular
member is expanded into contact with an interior portion of the outer casing.
According to another aspect of the present invention, an apparatus is
provided that includes an outer tubular member, and a plurality of
substantially concentric and overlapping inner tubular members coupled to the
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outer tubular member. Each inner tubular member is supported by contact
pressure between an outer surface of the inner casing and an inner surface of
the outer inner tubular member.
According to another aspect of the present invention, an apparatus is
provided that includes an outer tubular member, and a plurality of
substantially concentric inner tubular members coupled to the interior surface
of the outer tubular member by the process of expanding one or more of the
inner tubular members into contact with at least a portion of the interior
surface of the outer tubular member.
Brief Description of the Drawings
FIG. 1 is a fragmentary cross-sectional view illustrating the drilling of a
new section of a well borehole.
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.
FIG. 3 is a fragmentary cross-sectional view illustrating the injection of a
first quantity of a hardenable fluidic sealing material into the new section
of the
well borehole.
FIG. 3a is another fragmentary cross-sectional view illustrating the
injection of a first quantity of a hardenable fluidic sealing material into
the new
section of the well borehole.
FIG. 4 is a fragmentary cross-sectional view illustrating the injection of a
second quantity of a hardenable fluidic sealing material into the new section
of
the well borehole.
FIG. 5 is a fragmentary cross-sectional view illustrating the drilling out
of a portion of the cured hardenable fluidic sealing material from the new
section of the well borehole.
FIG. 6 is a cross-sectional view of an embodiment of the overlapping joint
between adjacent tubular members.
FIG. 7 is a fragmentary cross-sectional view of a preferred embodiment
of the apparatus for creating a casing within a well borehole.
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FIG. 8 is a fragmentary cross-sectional illustration of the placement of an
expanded tubular member within another tubular member.
FIG. 9 is a cross-sectional illustration of a preferred embodiment of an
apparatus for forming a casing including a drillable mandrel and shoe.
FIG. 9a is another cross-sectional illustration of the apparatus of FIG. 9.
FIG. 9b is another cross-sectional illustration of the apparatus of FIG. 9.
FIG. 9c is another cross-sectional illustration of the apparatus of FIG. 9.
FIG. l0a is a cross-sectional illustration of a wellbore including a pair of
adjacent overlapping casings.
FIG. lOb is a cross-sectional illustration of an apparatus and method for
creating a tie-back liner using an expandible tubular member.
FIG. 10c is a cross-sectional illustration of the pumping of a fluidic
sealing material into the annular region between the tubular member and the
existing casing.
FIG. lOd is a cross-sectional illustration of the pressurizing of the
interior of the tubular member below the mandrel.
FIG. 10e is a cross-sectional illustration of the extrusion of the tubular
member off of the mandrel.
FIG. lOf is a cross-sectional illustration of the tie-back liner before
drilling out the shoe and packer.
FIG. lOg is a cross-sectional illustration of the completed tie-back liner
created using an expandible tubular member.
FIG. 11a is a fragmentary cross-sectional view illustrating the drilling of
a new section of a well borehole.
FIG. 11b is a fragmentary cross-sectional view illustrating the placement
of an embodiment of an apparatus for hanging a tubular liner within the new
section of the well borehole.
FIG. llc is a fragmentary cross-sectional view illustrating the injection of
a first quantity of a fluidic material into the new section of the well
borehole.
FIG. 11d is a fragmentary cross-sectional view illustrating the
introduction of a wiper dart into the new section of the well borehole.
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FIG. 11e is a fragmentary cross-sectional view illustrating the injection of
a second quantity of a fluidic material into the new section of the well
borehole.
FIG. 11f is a fragmentary cross-sectional view illustrating the completion
of the tubular liner.
FIG. 12 is a cross-sectional illustration of a preferred embodiment of a
wellhead system utilizing expandable tubular members.
FIG. 13 is a partial cross-sectional illustration of a preferred embodiment
of the wellhead system of FIG. 12.
Detailed Description of the Illustrative Embodiments
An apparatus and method for forming a wellbore casing within a
subterranean formation is provided. The apparatus and method permits a
wellbore casing to be formed in a subterranean formation by placing a tubular
member and a mandrel in a new section of a wellbore, and then extruding the
tubular member off of the mandrel by pressurizing an interior portion of the
tubular member. The apparatus and method further permits adjacent tubular
members in the wellbore to be joined using an overlapping joint that prevents
fluid and or gas passage. The apparatus and method further permits a new
tubular member to be supported by an existing tubular member by expanding
the new tubular member into engagement with the existing tubular member.
The apparatus and method further minimizes the reduction in the hole size of
the wellbore casing necessitated by the addition of new sections of wellbore
casing.
An apparatus and method for forming a tie-back liner using an
expandable tubular member is also provided. The apparatus and method
permits a tie-back liner to be created by extruding a tubular member off of a
mandrel by pressurizing and interior portion of the tubular member. In this
manner, a tie-back liner is produced. The apparatus and method further
permits adjacent tubular members in the wellbore to be joined using an
overlapping joint that prevents fluid and/or gas passage. The apparatus and
method further permits a new tubular member to be supported by an existing
tubular member by expanding the new tubular member into engagement with
the existing tubular member.
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An apparatus and method for expanding a tubular member is also
provided that includes an expandable tubular member, mandrel and a shoe. In
a preferred embodiment, the interior portions of the apparatus is composed of
materials that permit the interior portions to be removed using a conventional
drilling apparatus. In this manner, in the event of a malfunction in a
downhole
region, the apparatus may be easily removed.
An apparatus and method for hanging an expandable tubular liner in a
wellbore is also provided. The apparatus and method permit a tubular liner to
be attached to an existing section of casing. The apparatus and method further
have application to the joining of tubular members in general.
An apparatus and method for forming a wellhead system is also provided.
The apparatus and method permit a wellhead to be formed including a number
of expandable tubular members positioned in a concentric arrangement. The
wellhead preferably includes an outer casing that supports a plurality of
concentric casings using contact pressure between the inner casings and the
outer casing. The resulting wellhead system eliminates many of the spools
conventionally required, reduces the height of the Christmas tree facilitating
servicing, lowers the load bearing areas of the wellhead resulting in a more
stable system, and eliminates costly and expensive hanger systems.
Referring initially to Figs. 1-5, an embodiment of an apparatus and method for
forming a wellbore casing within a subterranean formation will now be
described. As illustrated in Fig. 1, a wellbore 100 is positioned in a
subterranean formation 105. The wellbore 100 includes an existing cased
section 110 having a tubular casing 115 and an annular outer layer of cement
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 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. The apparatus 200 preferably includes an expandable mandrel or
pig 205, a tubular member 210, a shoe 215, a lower cup seal 220, an upper cup
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sea1225, a fluid passage 230, a fluid passage 235, a fluid passage 240, seals
245,
and a support member 250.
The expandable mandrel 205 is coupled to and supported by the support
member 250. The expandable mandre1205 is preferably adapted to controllably
expand in a radial direction. The expandable mandre1205 may comprise any
number of conventional commercially available expandable mandrels modified
in accordance with the teachings of the present disclosure. In a preferred
embodiment, the expandable mandre1205 comprises a hydraulic expansion tool
as disclosed in U.S. Patent No. 5,348,095, the contents of which are
incorporated herein by reference, modified in accordance with the teachings of
the present disclosure.
The tubular member 210 is supported by the expandable mandre1205.
The tubular member 210 is expanded in the radial direction and extruded off of
the expandable mandre1205. The 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 a preferred embodiment, the
tubular
member 210 is fabricated from OCTG in order to maximize strength after
expansion. The inner and outer diameters of the tubular member 210 may
range, for example, from approximately 0.75 to 47 inches and 1.05 to 48
inches,
respectively. In a preferred embodiment, the inner and outer diameters of the
tubular member 210 range from about 3 to 15.5 inches and 3.5 to 16 inches,
respectively in order to optimally provide minimal telescoping effect in the
most
commonly drilled wellbore sizes. The tubular member 210 preferably comprises
a solid member.
In a preferred embodiment, the end portion 260 of the tubular member
210 is slotted, perforated, or otherwise modified to catch or slow down the
mandre1205 when it completes the extrusion of tubular member 210. In a
preferred embodiment, the length of the tubular member 210 is limited to
minimize the possibility of buckling. For typical tubular member 210
materials,
the length of the tubular member 210 is preferably limited to between about 40
to 20,000 feet in length.
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The shoe 215 is coupled to the expandable mandrel 205 and the tubular
member 210. The shoe 215 includes fluid passage 240. The shoe 215 may
comprise 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 a preferred embodiment, the shoe 215
comprises 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 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 a preferred embodiment, the shoe 215 includes one or more through
and side outlet ports in fluidic communication with the fluid passage 240. In
this manner, the shoe 215 optimally injects hardenable fluidic sealing
material
into the region outside the shoe 215 and tubular member 210. In a preferred
embodiment, the shoe 215 includes the fluid passage 240 having an inlet
geometry that can receive a dart and/or a ball sealing member. In this manner,
the fluid passage 240 can be optimally sealed off by introducing a plug, dart
and/or ball sealing elements into the fluid passage 230.
The lower cup sea1220 is coupled to and supported by the support
member 250. The lower cup sea1220 prevents foreign materials from entering
the interior region of the tubular member 210 adjacent to the expandable
mandrel 205. The lower cup sea1220 may comprise 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 a preferred embodiment, the lower cup sea1220
comprises 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.
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The upper cup seal 225 is coupled to and supported by the support
member 250. The upper cup seal 225 prevents foreign materials from entering
the interior region of the tubular member 210. The upper cup seal 225 may
comprise 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 a preferred embodiment, the upper cup seal 225
comprises 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.
The fluid passage 230 permits fluidic materials to be transported to and
from the interior region of the tubular member 210 below the expandable
mandre1205. The fluid passage 230 is coupled to and positioned within the
support member 250 and the expandable mandrel 205. The fluid passage 230
preferably extends from a position adjacent to the surface to the bottom of
the
expandable mandrel 205. The fluid passage 230 is preferably positioned along a
centerline of the apparatus 200.
The fluid passage 230 is preferably selected, in the casing running mode
of operation, to transport materials such as 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 which could cause a loss of
wellbore fluids and lead to hole collapse.
The fluid passage 235 permits fluidic materials to be released from the
fluid passage 230. In this manner, during placement of the apparatus 200
within the new section 130 of the wellbore 100, fluidic materials 255 forced
up
the fluid passage 230 can be released into the wellbore 100 above the tubular
member 210 thereby minimizing surge pressures on the wellbore section 130.
The fluid passage 235 is coupled to and positioned within the support member
250. The fluid passage is further fluidicly coupled to the fluid passage 230.
The fluid passage 235 preferably includes a control valve for controllably
opening and closing the fluid passage 235. In a preferred embodiment, the
control valve is pressure activated in order to controllably minimize surge
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pressures. The fluid passage 235 is preferably positioned substantially
orthogonal to the centerline of the apparatus 200.
The fluid passage 235 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.
The fluid passage 240 permits fluidic materials to be transported to and
from the region exterior to the tubular member 210 and shoe 215. The fluid
passage 240 is coupled to and positioned within the shoe 215 in fluidic
communication with the interior region of the tubular member 210 below the
expandable mandre1205. The fluid passage 240 preferably has a cross-sectional
shape that permits a plug, or other similar device, to be placed in fluid
passage
240 to thereby block further passage of fluidic materials. In this manner, the
interior region of the tubular member 210 below the expandable mandrel 205
can be fluidicly isolated from the region exterior to the tubular member 210.
This permits the interior region of the tubular member 210 below the
expandable mandrel 205 to be pressurized. The fluid passage 240 is preferably
positioned substantially along the centerline of the apparatus 200.
The fluid passage 240 is preferably selected to convey materials such as
cement, drilling mud or epoxies at flow rates and pressures ranging from about
0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the
annular region between the tubular member 210 and the new section 130 of the
welibore 100 with fluidic materials. In a preferred embodiment, the fluid
passage 240 includes an inlet geometry that can receive a dart and/or a ball
sealing member. In this manner, the fluid passage 240 can be sealed off by
introducing a plug, dart and/or ball sealing elements into the fluid passage
230.
The seals 245 are coupled to and supported by an end portion 260 of the
tubular member 210. The seals 245 are further positioned on an outer surface
265 of the end portion 260 of the tubular member 210. The seals 245 permit
the overlapping joint between the end portion 270 of the casing 115 and the
portion 260 of the tubular member 210 to be fluidicly sealed. The seals 245
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may comprise 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 a preferred embodiment, the seals
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 end 260 of the tubular member 210 and the end 270 of the
existing casing 115.
In a preferred embodiment, the seals 245 are selected to optimally
provide a sufficient frictional force to support the expanded tubular member
210 from the existing casing 115. In a preferred embodiment, the frictional
force optimally provided by the seals 245 ranges from about 1,000 to 1,000,000
lbf in order to optimally support the expanded tubular member 210.
The support member 250 is coupled to the expandable mandrel 205,
tubular member 210, shoe 215, and seals 220 and 225. The support member
250 preferably comprises an annular member having sufficient strength to
carry the apparatus 200 into the new section 130 of the wellbore 100. In a
preferred embodiment, the support member 250 further includes one or more
conventional centralizers (not illustrated) to help stabilize the apparatus
200.
In a preferred embodiment, a quantity of lubricant 275 is provided in the
annular region above the expandable mandre1205 within the interior of the
tubular member 210. In this manner, the extrusion of the tubular member 210
off of the expandable mandrel 205 is facilitated. The lubricant 275 may
comprise any number of conventional commercially available lubricants such
as, for example, Lubriplate, chlorine based lubricants, oil based lubricants
or
Climax 1500 Antisieze (3100). In a preferred embodiment, the lubricant 275
comprises 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 a preferred embodiment, the support member 250 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
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minimized. This minimizes the possibility of foreign material clogging the
various flow passages and valves of the apparatus 200.
In a preferred 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. 3, the fluid passage 235 is then closed and a
hardenable fluidic sealing material 305 is then pumped from a surface location
into the fluid passage 230. The material 305 then passes from the fluid
passage
230 into the interior region 310 of the tubular member 210 below the
expandable mandre1205. The materia1305 then passes from the interior region
310 into the fluid passage 240. The materia1305 then exits the apparatus 200
and fills the annular region 315 between the exterior of the tubular member
210 and the interior wall of the new section 130 of the wellbore 100.
Continued
pumping of the materia1305 causes the material 305 to fill up at least a
portion
of the annular region 315.
The materia1305 is preferably pumped into the annular region 315 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 materia1305 may comprise any number of
conventional commercially available hardenable fluidic sealing materials such
as, for example, slag mix, cement or epoxy. In a preferred embodiment, the
hardenable fluidic sealing materia1305 comprises 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 tubular member
210 while also maintaining optimum flow characteristics so as to minimize
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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.
The annular region 315 preferably is filled with the material 305 in
sufficient quantities to ensure that, upon radial expansion of the tubular
member 210, the annular region 315 of the new section 130 of the wellbore 100
will be filled with materia1305.
In a particularly preferred embodiment, as illustrated in Fig. 3a, the wall
thickness and/or the outer diameter of the tubular member 210 is reduced in
the region adjacent to the mandrel 205 in order optimally permit placement of
the apparatus 200 in positions in the wellbore with tight clearances.
Furthermore, in this manner, the initiation of the radial expansion of the
tubular member 210 during the extrusion process is optimally facilitated.
As illustrated in Fig. 4, once the annular region 315 has been adequately
filled with material 305, a plug 405, or other similar device, is introduced
into
the fluid passage 240 thereby fluidicly isolating the interior region 310 from
the
annular region 315. In a preferred embodiment, a non-hardenable fluidic
material 306 is then pumped into the interior region 310 causing the interior
region to pressurize. In this manner, the interior of the expanded tubular
member 210 will not contain significant amounts of cured material 305. This
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 310 becomes sufficiently pressurized, the
tubular member 210 is extruded off of the expandable mandre1205. During the
extrusion process, the expandable mandre1205 may be raised out of the
expanded portion of the tubular member 210. In a preferred embodiment,
during the extrusion process, the mandre1205 is raised at approximately the
same rate as the tubular member 210 is expanded in order to keep the tubular
member 210 stationary relative to the new wellbore section 130. In an
alternative preferred embodiment, the extrusion process is commenced with the
tubular member 210 positioned above the bottom of the new wellbore section
130, keeping the mandre1205 stationary, and allowing the tubular member 210
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to extrude off of the mandrel 205 and fall down the new wellbore section 130
under the force of gravity.
The plug 405 is preferably placed into the fluid passage 240 by
introducing the plug 405 into the fluid passage 230 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 306.
The plug 405 may comprise 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 a preferred embodiment, the plug 405 comprises a MSC latch-
down plug available from Halliburton Energy Services in Dallas, TX.
After placement of the plug 405 in the fluid passage 240, a non
hardenable fluidic material 306 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 310 of the tubular
member 210 is minimized. In a preferred embodiment, after placement of the
plug 405 in the fluid passage 240, the non hardenable material 306 is
preferably
pumped into the interior region 310 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 a preferred embodiment, the apparatus 200 is adapted to minimize
tensile, burst, and friction effects upon the tubular member 210 during the
expansion process. These effects will be depend upon the geometry of the
expansion mandrel 205, the material composition of the tubular member 210
and expansion mandrel 205, the inner diameter of the tubular member 210, the
wall thickness of the tubular member 210, the type of lubricant, and the yield
strength of the tubular member 210. In general, the thicker the wall
thickness,
the smaller the inner diameter, and the greater the yield strength of the
tubular
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member 210, then the greater the operating pressures required to extrude the
tubular member 210 off of the mandrel 205.
For typical tubular members 210, the extrusion of the tubular member
210 off of the expandable mandrel will begin when the pressure of the interior
region 310 reaches, for example, approximately 500 to 9,000 psi.
During the extrusion process, the expandable mandrel 205 may be raised
out of the expanded portion of the tubular member 210 at rates ranging, for
example, from about 0 to 5 ft/sec. In a preferred embodiment, during the
extrusion process, the expandable mandrel 205 is raised out of the expanded
portion of the 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 end portion 260 of the tubular member 210 is extruded off of
the expandable mandrel 205, the outer surface 265 of the end portion 260 of
the
tubular member 210 will preferably contact the interior surface 410 of the end
portion 270 of the 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 a preferred 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 section 410 of the existing casing 115
and the section 265 of the expanded tubular member 210 preferably provides a
gaseous and fluidic seal. In a particularly preferred embodiment, the sealing
members 245 optimally provide a fluidic and gaseous seal in the overlapping
joint.
In a preferred embodiment, the operating pressure and flow rate of the
non hardenable fluidic material 306 is controllably ramped down when the
expandable mandrel 205 reaches the end portion 260 of the tubular member
210. In this manner, the sudden release of pressure caused by the complete
extrusion of the tubular member 210 off of the expandable mandre1205 can be
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minimized. In a preferred 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 mandrel 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 250 in order to absorb the shock caused by the sudden release
of pressure. The shock absorber may comprise, for example, any conventional
commercially available shock absorber adapted for use in wellbore operations.
Alternatively, or in combination, a mandrel catching structure is
provided in the end portion 260 of the tubular member 210 in order to catch or
at least decelerate the mandrel 205.
Once the extrusion process is completed, the expandable mandrel 205 is
removed from the wellbore 100. In a preferred embodiment, either before or
after the removal of the expandable mandrel 205, the integrity of the fluidic
seal
of the overlapping joint between the upper portion 260 of the tubular member
210 and the lower portion 270 of the casing 115 is tested using conventional
methods.
If the fluidic seal of the overlapping joint between the upper portion 260
of the tubular member 210 and the lower portion 270 of the casing 115 is
satisfactory, then any uncured portion of the material 305 within the expanded
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 mandrel 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
tubular
member 210. The material 305 within the annular region 315 is then allowed
to 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 includes the expanded tubular member 210 and an outer
annular layer 515 of cured material 305. The bottom portion of the apparatus
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200 comprising the shoe 215 and dart 405 may then be removed by drilling out
the shoe 215 and dart 405 using conventional drilling methods.
In a preferred embodiment, as illustrated in Fig. 6, the upper portion 260
of the tubular member 210 includes one or more sealing members 605 and one
or more pressure relief holes 610. In this manner, the overlapping joint
between the lower portion 270 of the casing 115 and the upper portion 260 of
the tubular member 210 is pressure-tight and the pressure on the interior and
exterior surfaces of the tubular member 210 is equalized during the extrusion
process.
In a preferred embodiment, the sealing members 605 are seated within
recesses 615 formed in the outer surface 265 of the upper portion 260 of the
tubular member 210. In an alternative preferred embodiment, the sealing
members 605 are bonded or molded onto the outer surface 265 of the upper
portion 260 of the tubular member 210. The pressure relief holes 610 are
preferably positioned in the last few feet of the tubular member 210. The
pressure relief holes reduce the operating pressures required to expand the
upper portion 260 of the tubular member 210. This reduction in required
operating pressure in turn reduces the velocity of the mandrel 205 upon the
completion of the extrusion process. This reduction in velocity in turn
minimizes the mechanical shock to the entire apparatus 200 upon the
completion of the extrusion process.
Referring now to Fig. 7, a particularly preferred embodiment of an
apparatus 700 for forming a casing within a wellbore preferably includes an
expandable mandrel or pig 705, an expandable mandrel or pig container 710, a
tubular member 715, a float shoe 720, a lower cup seal 725, an upper cup seal
730, a fluid passage 735, a fluid passage 740, a support member 745, a body of
lubricant 750, an overshot connection 755, another support member 760, and a
stabilizer 765.
The expandable mandrel 705 is coupled to and supported by the support
member 745. The expandable mandrel 705 is further coupled to the expandable
mandrel container 710. The expandable mandrel 705 is preferably adapted to
controllably expand in a radial direction. The expandable mandrel 705 may
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comprise any number of conventional commercially available expandable
mandrels modified in accordance with the teachings of the present disclosure.
In a preferred embodiment, the expandable mandre1705 comprises a hydraulic
expansion tool substantially as disclosed in U.S. Pat. No. 5,348,095, the
contents of which are incorporated herein by reference, modified in accordance
with the teachings of the present disclosure.
The expandable mandrel container 710 is coupled to and supported by
the support member 745. The expandable mandrel container 710 is further
coupled to the expandable mandrel 705. The expandable mandrel container 710
may be constructed from any number of conventional commercially available
materials such as, for example, Oilfield Country Tubular Goods, stainless
steel,
titanium or high strength steels. In a preferred embodiment, the expandable
mandrel container 710 is fabricated from material having a greater strength
than the material from which the tubular member 715 is fabricated. In this
manner, the container 710 can be fabricated from a tubular material having a
thinner wall thickness than the tubular member 210. This permits the
container 710 to pass through tight clearances thereby facilitating its
placement
within the wellbore.
In a preferred embodiment, once the expansion process begins, and the
thicker, lower strength material of the tubular member 715 is expanded, the
outside diameter of the tubular member 715 is greater than the outside
diameter of the container 710.
The tubular member 715 is coupled to and supported by the expandable
mandrel 705. The tubular member 715 is preferably expanded in the radial
direction and extruded off of the expandable mandrel 705 substantially as
described above with reference to Figs. 1-6. The tubular member 715 may be
fabricated from any number of materials such as, for example, Oilfield Country
Tubular Goods (OCTG), automotive grade steel or plastics. In a preferred
embodiment, the tubular member 715 is fabricated from OCTG.
In a preferred embodiment, the tubular member 715 has a substantially
annular cross-section. In a particularly preferred embodiment, the tubular
member 715 has a substantially circular annular cross-section.
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The tubular member 715 preferably includes an upper section 805, an
intermediate section 810, and a lower section 815. The upper section 805 of
the
tubular member 715 preferably is defined by the region beginning in the
vicinity of the mandrel container 710 and ending with the top section 820 of
the
tubular member 715. The intermediate section 810 of the tubular member 715
is preferably defined by the region beginning in the vicinity of the top of
the
mandrel container 710 and ending with the region in the vicinity of the
mandrel 705. The lower section of the tubular member 715 is preferably
defined by the region beginning in the vicinity of the mandrel 705 and ending
at
the bottom 825 of the tubular member 715.
In a preferred embodiment, the wall thickness of the upper section 805 of
the tubular member 715 is greater than the wall thicknesses of the
intermediate
and lower sections 810 and 815 of the tubular member 715 in order to optimally
faciliate the initiation of the extrusion process and optimally permit the
apparatus 700 to be positioned in locations in the wellbore having tight
clearances.
The outer diameter and wall thickness of the upper section 805 of the
tubular member 715 may range, for example, from about 1.05 to 48 inches and
1/8 to 2 inches, respectively. In a preferred embodiment, the outer diameter
and wall thickness of the upper section 805 of the tubular member 715 range
from about 3.5 to 16 inches and 3/8 to 1.5 inches, respectively.
The outer diameter and wall thickness of the intermediate section 810 of
the tubular member 715 may range, for example, from about 2.5 to 50 inches
and 1/16 to 1.5 inches, respectively. In a preferred embodiment, the outer
diameter and wall thickness of the intermediate section 810 of the tubular
member 715 range from about 3.5 to 19 inches and 1/8 to 1.25 inches,
respectively.
The outer diameter and wall thickness of the lower section 815 of the
tubular member 715 may range, for example, from about 2.5 to 50 inches and
1/16 to 1.25 inches, respectively. In a preferred embodiment, the outer
diameter and wall thickness of the lower section 810 of the tubular member 715
range from about 3.5 to 19 inches and 1/8 to 1.25 inches, respectively. In a
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particularly preferred embodiment, the wall thickness of the lower section 815
of the tubular member 715 is further increased to increase the strength of the
shoe 720 when drillable materials such as, for example, aluminum are used.
The tubular member 715 preferably comprises a solid tubular member.
In a preferred embodiment, the end portion 820 of the tubular member 715 is
slotted, perforated, or otherwise modified to catch or slow down the mandrel
705 when it completes the extrusion of tubular member 715. In a preferred
embodiment, the length of the tubular member 715 is limited to minimize the
possibility of buckling. For typical tubular member 715 materials, the length
of
the tubular member 715 is preferably limited to between about 40 to 20,000
feet
in length.
The shoe 720 is coupled to the expandable mandrel 705 and the tubular
member 715. The shoe 720 includes the fluid passage 740. In a preferred
embodiment, the shoe 720 further includes an inlet passage 830, and one or
more jet ports 835. In a particularly preferred embodiment, the cross-
sectional
shape of the inlet passage 830 is adapted to receive a latch-down dart, or
other
similar elements, for blocking the inlet passage 830. The interior of the shoe
720 preferably includes a body of solid material 840 for increasing the
strength
of the shoe 720. In a particularly preferred embodiment, the body of solid
material 840 comprises aluminum.
The shoe 720 may comprise any number of conventional commercially
available shoes such as, for example, Super Seal II Down-Jet float shoe, or
guide
shoe with a sealing sleeve for a latch down plug modified in accordance with
the
teachings of the present disclosure. In a preferred embodiment, the shoe 720
comprises 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
optimize
guiding the tubular member 715 in the wellbore, optimize the seal between the
tubular member 715 and an existing wellbore casing, and to optimally faciliate
the removal of the shoe 720 by drilling it out after completion of the
extrusion
process.
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The lower cup seal 725 is coupled to and supported by the support
member 745. The lower cup seal 725 prevents foreign materials from entering
the interior region of the tubular member 715 above the expandable mandrel
705. The lower cup seal 725 may comprise 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 a preferred embodiment, the lower cup seal 725
comprises a SIP cup, available from Halliburton Energy Services in Dallas, TX
in order to optimally provide a debris barrier and hold a body of lubricant.
The upper cup seal 730 is coupled to and supported by the support
member 760. The upper cup seal 730 prevents foreign materials from entering
the interior region of the tubular member 715. The upper cup sea1730 may
comprise any number of conventional commercially available cup seals such as,
for example, TP cups or Selective Injection Packer (SIP) cup modified in
accordance with the teachings of the present disclosure. In a preferred
embodiment, the upper cup seal 730 comprises a SIP cup available from
Halliburton Energy Services in Dallas, TX in order to optimally provide a
debris
barrier and contain a body of lubricant.
The fluid passage 735 permits fluidic materials to be transported to and
from the interior region of the tubular member 715 below the expandable
mandrel 705. The fluid passage 735 is fluidicly coupled to the fluid passage
740.
The fluid passage 735 is preferably coupled to and positioned within the
support
member 760, the support member 745, the mandrel container 710, and the
expandable mandrel 705. The fluid passage 735 preferably extends from a
position adjacent to the surface to the bottom of the expandable mandrel 705.
The fluid passage 735 is preferably positioned along a centerline of the
apparatus 700. The fluid passage 735 is preferably selected to transport
materials such as cement, drilling mud or epoxies at flow rates and pressures
ranging from about 40 to 3,000 gallons/minute and 500 to 9,000 psi in order to
optimally provide sufficient operating pressures to extrude the tubular member
715 off of the expandable mandrel 705.
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As described above with reference to Figs. 1-6, during placement of the
apparatus 700 within a new section of a wellbore, fluidic materials forced up
the
fluid passage 735 can be released into the wellbore above the tubular member
715. In a preferred embodiment, the apparatus 700 further includes a pressure
release passage that is coupled to and positioned within the support member
260. The pressure release passage is further fluidicly coupled to the fluid
passage 735. The pressure release passage preferably includes a control valve
for controllably opening and closing the fluid passage. In a preferred
embodiment, the control valve is pressure activated in order to controllably
minimize surge pressures. The pressure release passage is preferably
positioned substantially orthogonal to the centerline of the apparatus 700.
The
pressure release passage is preferably selected to convey materials such as
cement, drilling mud or epoxies at flow rates and pressures ranging from about
0 to 500 gallons/minute and 0 to 1,000 psi in order to reduce the drag on the
apparatus 700 during insertion into a new section of a wellbore and to
minimize
surge pressures on the new wellbore section.
The fluid passage 740 permits fluidic materials to be transported to and
from the region exterior to the tubular member 715. The fluid passage 740 is
preferably coupled to and positioned within the shoe 720 in fluidic
communication with the interior region of the tubular member 715 below the
expandable mandre1705. The fluid passage 740 preferably has a cross-sectional
shape that permits a plug, or other similar device, to be placed in the inlet
830
of the fluid passage 740 to thereby block further passage of fluidic
materials. In
this manner, the interior region of the tubular member 715 below the
expandable mandrel 705 can be optimally fluidicly isolated from the region
exterior to the tubular member 715. This permits the interior region of the
tubular member 715 below the expandable mandrel 205 to be pressurized.
The fluid passage 740 is preferably positioned substantially along the
centerline of the apparatus 700. The fluid passage 740 is preferably selected
to
convey materials such as cement, drilling mud or epoxies at flow rates and
pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in
order to optimally fill an annular region between the tubular member 715 and a
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new section of a wellbore with fluidic materials. In a preferred embodiment,
the fluid passage 740 includes an inlet passage 830 having a geometry that can
receive a dart and/or a ball sealing member. In this manner, the fluid passage
240 can be sealed off by introducing a plug, dart and/or ball sealing elements
into the fluid passage 230.
In a preferred embodiment, the apparatus 700 further includes one or
more seals 845 coupled to and supported by the end portion 820 of the tubular
member 715. The seals 845 are further positioned on an outer surface of the
end portion 820 of the tubular member 715. The seals 845 permit the
overlapping joint between an end portion of preexisting casing and the end
portion 820 of the tubular member 715 to be fluidicly sealed. The seals 845
may comprise 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 a preferred embodiment, the seals
845 comprise seals molded from StrataLock epoxy available from Halliburton
Energy Services in Dallas, TX in order to optimally provide a hydraulic seal
and
a load bearing interference fit in the overlapping joint between the tubular
member 715 and an existing casing with optimal load bearing capacity to
support the tubular member 715.
In a preferred embodiment, the seals 845 are selected to provide a
sufficient frictional force to support the expanded tubular member 715 from
the
existing casitig. In a preferred embodiment, the frictional force provided by
the
seals 845 ranges from about 1,000 to 1,000,0001bf in order to optimally
support
the expanded tubular member 715.
The support member 745 is preferably coupled to the expandable
mandre1705 and the overshot connection 755. The support member 745
preferably comprises an annular member having sufficient strength to carry the
apparatus 700 into a new section of a wellbore. The support member 745 may
comprise any number of conventional commercially available support members
such as, for example, steel drill pipe, coiled tubing or other high strength
tubular modified in accordance with the teachings of the present disclosure.
In
* trade-mark
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a preferred embodiment, the support member 745 comprises conventional drill
pipe available from various steel mills in the United States.
In a preferred embodiment, a body of lubricant 750 is provided in the
annular region above the expandable mandrel container 710 within the interior
of the tubular member 715. In this manner, the extrusion of the tubular
member 715 off of the expandable mandre1705 is facilitated. The lubricant 705
may comprise any number of conventional commercially available lubricants
such as, for example, Lubriplate chlorine based lubricants, oil based
lubricants,
or Climax 1500 Antisieze (3100). In a preferred embodiment, the lubricant 750
comprises Climax 1500 Antisiezt(3100) available from Halliburton Energy
Services in Houston, TX in order to optimally provide lubrication to faciliate
the
extrusion process.
The overshot connection 755 is coupled to the support member 745 and
the support member 760. The overshot connection 755 preferably permits the
support member 745 to be removably coupled to the support member 760. The
overshot connection 755 may comprise any number of conventional
commercially available overshot connections such as, for example, Innerstring
Sealing Adapter Innerstring Flat-Face Sealing Adapter or EZ DriIl Setting Tool
Stingei* In a preferred embodiment, the, overshot connection 755 comprises a
Innerstring Adapter with an Upper Guide available from Halliburton Energy
Services in Dallas, TX.
The support member 760 is preferably coupled to the overshot
connection 755 and a surface support structure (not illustrated). The support
member 760 preferably comprises an annular member having sufficient
strength to carry the apparatus 700 into a new section of a wellbore. The
support member 760 may comprise any number of conventional commercially
available support members such as, for example, steel drill pipe, coiled
tubing or
other high strength tubulars modified in accordance with the teachings of the
present disclosure. In a preferred embodiment, the support member 760
comprises a conventional driD. pipe available from steel mills in the United
States.
* trade-mark
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The stabilizer 765 is preferably coupled to the support member 760. The
stabilizer 765 also preferably stabilizes the components of the apparatus 700
within the tubular member 715. The stabilizer 765 preferably comprises a
spherical member having an outside diameter that is about 80 to 99% of the
interior diameter of the tubular member 715 in order to optimally minimize
buckling of the tubular member 715. The stabilizer 765 may comprise any
number of conventional commercially available stabilizers such as, for
example,
EZ Drill Star Guides packer shoes or drag blocks modified in accordance with
the teachings of the present disclosure. In a preferred embodiment, the
stabilizer 765 comprises a sealing adapter upper guide available from
Halliburton Energy Services in Dallas, TX.
In a preferred embodiment, the support members 745 and 760 are
thoroughly cleaned prior to assembly to the remaining portions of the
apparatus 700. In this manner, the introduction of foreign material into the
apparatus 700 is minimized. This minimizes the possibility of foreign'material
clogging the various flow passages and valves of the apparatus 700.
In a preferred embodiment, before or after positioning the apparatus 700
within a new section of a wellbore, a couple of wellbore volumes are
circulated
through the various flow passages of the apparatus 700 in order to ensure that
no foreign materials are located within the wellbore that might clog up the
various flow passages and valves of the apparatus 700 and to ensure that no
foreign material interferes with the expansion mandrel 705 during the
expansion process.
In a preferred embodiment, the apparatus 700 is operated substantially
as described above with reference to Figs. 1-7 to form a new section of casing
within a wellbore.
As illustrated in Fig. 8, in an alternative preferred embodiment, the
method and apparatus described herein is used to repair an existing wellbore
casing 805 by forming a tubular liner 810 inside of the existing wellbore
casing
805. In a preferred embodiment, an outer annular lining of cement is not
provided in the repaired section. In the alternative preferred embodiment, any
number of fluidic materials can be used to expand the tubular liner 810 into
* trade-mark
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intimate contact with the damaged section of the wellbore casing such as, for
example, cement, epoxy, slag mix, or drilling mud. In the alternative
preferred
embodiment, sealing members 815 are preferably provided at both ends of the
tubular member in order to optimally provide a fluidic seal. In an alternative
preferred embodiment, the tubular liner 810 is formed within a horizontally
positioned pipeline section, such as those used to transport hydrocarbons or
water, with the tubular liner 810 placed in an overlapping relationship with
the
adjacent pipeline section. In this manner, underground pipelines can be
repaired without having to dig out and replace the damaged sections.
In another alternative preferred embodiment, the method and apparatus
described herein is used to directly line a wellbore with a tubular liner 810.
In
a preferred embodiment, an outer annular lining of cement is not provided
between the tubular liner 810 and the wellbore. In the alternative preferred
embodiment, any number of fluidic materials can be used to expand the tubular
liner 810 into intimate contact with the wellbore such as, for example,
cement,
epoxy, slag mix, or drilling mud.
Referring now to Figs. 9, 9a, 9b and 9c, a preferred embodiment of an
apparatus 900 for forming a wellbore casing includes an expandible tubular
member 902, a support member 904, an expandible mandrel or pig 906, and a
shoe 908. In a preferred embodiment, the design and construction of the
mandrel 906 and shoe 908 permits easy removal of those elements by drilling
them out. In this manner, the assembly 900 can be easily removed from a
wellbore using a conventional drilling apparatus and corresponding drilling
methods.
The expandible tubular member 902 preferably includes an upper
portion 910, an intermediate portion 912 and a lower portion 914. During
operation of the apparatus 900, the tubular member 902 is preferably extruded
off of the mandre1906 by pressurizing an interior region 966 of the tubular
member 902. The tubular member 902 preferably has a substantially annular
cross-section.
In a particularly preferred embodiment, an expandable tubular member
915 is coupled to the upper portion 910 of the expandable tubular member 902.
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During operation of the apparatus 900, the tubular member 915 is preferably
extruded off of the mandre1906 by pressurizing the interior region 966 of the
tubular member 902. The tubular member 915 preferably has a substantially
annular cross-section. In a preferred embodiment, the wall thickness of the
tubular member 915 is greater than the wall thickness of the tubular member
902.
The tubular member 915 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
tubulars, low alloy steels, titanium or stainless steels. In a preferred
embodiment, the tubular member 915 is fabricated from oilfield tubulars in
order to optimally provide approximately the same mechanical properties as the
tubular member 902. In a particularly preferred embodiment, the tubular
member 915 has a plastic yield point ranging from about 40,000 to 135,000 psi
in order to optimally provide approximately the same yield properties as the
tubular member 902. The tubular member 915 may comprise a plurality of
tubular members coupled end to end.
In a preferred embodiment, the upper end portion of the tubular member
915 includes one or more sealing members for optimally providing a fluidic
and/or gaseous seal with an existing section of wellbore casing.
In a preferred embodiment, the combined length of the tubular members
902 and 915 are limited to minimize the possibility of buckling. For typical
tubular member materials, the combined length of the tubular members 902
and 915 are limited to between about 40 to 20,000 feet in length.
The lower portion 914 of the tubular member 902 is preferably coupled to
the shoe 908 by a threaded connection 968. The intermediate portion 912 of the
tubular member 902 preferably is placed in intimate sliding contact with the
mandre1906.
The tubular member 902 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
tubulars, low alloy steels, titanium or stainless steels. In a preferred
embodiment, the tubular member 902 is fabricated from oilfield tubulars in
order to optimally provide approximately the same mechanical properties as the
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tubular member 915. In a particularly preferred embodiment, the tubular
member 902 has a plastic yield point ranging from about 40,000 to 135,000 psi
in order to optimally provide approximately the same yield properties as the
tubular member 915.
The wall thickness of the upper, intermediate, and lower portions, 910,
912 and 914 of the tubular member 902 may range, for example, from about
1/16 to 1.5 inches. In a preferred embodiment, the wall thickness of the
upper,
intermediate, and lower portions, 910, 912 and 914 of the tubular member 902
range from about 1/8 to 1.25 in order to optimally provide wall thickness that
are about the same as the tubular member 915. In a preferred embodiment, the
wall thickness of the lower portion 914 is less than or equal to the wall
thickness of the upper portion 910 in order to optimally provide a geometry
that
will fit into tight clearances downhole.
The outer diameter of the upper, intermediate, and lower portions, 910,
912 and 914 of the tubular member 902 may range, for example, from about
1.05 to 48 inches. In a preferred embodiment, the outer diameter of the upper,
intermediate, and lower portions, 910, 912 and 914 of the tubular member 902
range from about 3 1/2 to 19 inches in order to optimally provide the ability
to
expand the most commonly used oilfield tubulars.
The length of the tubular member 902 is preferably limited to between
about 2 to 5 feet in order to optimally provide enough length to contain the
mandrel 906 and a body of lubricant.
The tubular member 902 may comprise any number of conventional
commercially available tubular members modified in accordance with the
teachings of the present disclosure. In a preferred embodiment, the tubular
member 902 comprises Oilfield Country Tubular Goods available from various
U.S. steel mills. The tubular member 915 may comprise any number of
conventional commercially available tubular members modified in accordance
with the teachings of the present disclosure. In a preferred embodiment, the
tubular member 915 comprises Oilfield Country Tubular Goods available from
various U.S. steel mills.
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The various elements of the tubular member 902 may be coupled using
any number of conventional process such as, for example, threaded connections,
welding or machined from one piece. In a preferred embodiment, the various
elements of the tubular member 902 are coupled using welding. The tubular
member 902 may comprise a plurality of tubular elements that are coupled end
to end. The various elements of the tubular member 915 may be coupled using
any number of conventional process such as, for example, threaded connections,
welding or machined from one piece. In a preferred embodiment, the various
elements of the tubular member 915 are coupled using welding. The tubular
member 915 may comprise a plurality of tubular elements that are coupled end
to end. The tubular members 902 and 915 may be coupled using any number of
conventional process such as, for example, threaded connections, welding or
machined from one piece.
The support member 904 preferably includes an innerstring adapter 916,
a fluid passage 918, an upper guide 920, and a coupling 922. During operation
of the apparatus 900, the support member 904 preferably supports the
apparatus 900 during movement of the apparatus 900 within a wellbore. The
support member 904 preferably has a substantially annular cross-section.
The support member 904 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
tubulars, low alloy steel, coiled tubing or stainless steel. In a preferred
embodiment, the support member 904 is fabricated from low alloy steel in order
to optimally provide high yield strength.
The innerstring adaptor 916 preferably is coupled to and supported by a
conventional drill string support from a surface location. The innerstring
adaptor 916 may be coupled to a conventional drill string support 971 by a
threaded connection 970.
The fluid passage 918 is preferably used to convey fluids and other
materials to and from the apparatus 900. In a preferred embodiment, the fluid
passage 918 is fluidicly coupled to the fluid passage 952. In a preferred
embodiment, the fluid passage 918 is used to convey hardenable fluidic sealing
materials to and from the apparatus 900. In a particularly preferred
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embodiment, the fluid passage 918 may include one or more pressure relief
passages (not illustrated) to release fluid pressure during positioning of the
apparatus 900 within a wellbore. In a preferred embodiment, the fluid passage
918 is positioned along a longitudinal centerline of the apparatus 900. In a
preferred embodiment, the fluid passage 918 is selected to permit the
conveyance of hardenable fluidic materials at operating pressures ranging from
about 0 to 9,000 psi.
The upper guide 920 is coupled to an upper portion of the support
member 904. The upper guide 920 preferably is adapted to center the support
member 904 within the tubular member 915. The upper guide 920 may
comprise any number of conventional guide members modified in accordance
with the teachings of the present disclosure. In a preferred embodiment, the
upper guide 920 comprises an innerstring adapter available from Halliburton
Energy Services in Dallas, TX order to optimally guide the apparatus 900
within the tubular member 915.
The coupling 922 couples the support member 904 to the mandrel 906.
The coupling 922 preferably comprises a conventional threaded connection.
The various elements of the support member 904 may be coupled using
any number of conventional processes such as, for example, welding, threaded
connections or machined from one piece. In a preferred embodiment, the
various elements of the support member 904 are coupled using threaded
connections.
The mandrel 906 preferably includes a retainer 924, a rubber cup 926, an
expansion cone 928, a lower cone retainer 930, a body of cement 932, a lower
guide 934, an extension sleeve 936, a spacer 938, a housing 940, a sealing
sleeve
942, an upper cone retainer 944, a lubricator mandrel 946, a lubricator sleeve
948, a guide 950, and a fluid passage 952.
The retainer 924 is coupled to the lubricator mandrel 946, lubricator
sleeve 948, and the rubber cup 926. The retainer 924 couples the rubber cup
926 to the lubricator sleeve 948. The retainer 924 preferably has a
substantially
annular cross-section. The retainer 924 may comprise any number of
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conventional commercially available retainers such as, for example, slotted
spring pins or roll pin.
The rubber cup 926 is coupled to the retainer 924, the lubricator mandrel
946, and the lubricator sleeve 948. The rubber cup 926 prevents the entry of
foreign materials into the interior region 972 of the tubular member 902 below
the rubber cup 926. The rubber cup 926 may comprise any number of
conventional commercially available rubber cups such as, for example, TPcups
or Selective Injection Packer (SIP) cup. In a preferred embodiment, the rubber
cup 926 comprises a SIP cup available from Halliburton Energy Services in
Dallas, TX in order to optimally block -foreign materials.
In a particularly preferred embodiment, a body of lubricant is further
provided in the interior region 972 of the tubular member 902 in order to
lubricate the interface between the exterior surface of the mandre1902 and the
interior surface of the tubular members 902 and 915. The lubricant may
comprise any number of conventional commercially available lubricants such
as, for example, Lubriplate, chlorine based lubricants, oil based lubricants
or
Climax 1500 Antiseize (3100). In a preferred embodiment, the lubricant
comprises Climax 1500 Antiseize (3100) available from Climax Lubricants and
Equipment Co. in Houston, TX in order to optimally provide lubrication to
faciliate the extrusion process.
The expansion cone 928 is coupled to the lower cone retainer 930, the
body of cement 932, the lower guide 934, the extension sleeve 936, the housing
940, and the upper cone retainer 944. In a preferred embodiment, during
operation of the apparatus 900, the tubular members 902 and 915 are extruded
off of the outer surface of the expansion cone 928. In a preferred embodiment,
axial movement of the expansion cone 928 is prevented by the lower cone
retainer 930, housing 940 and the upper cone retainer 944. Inner radial
movement of the expansion cone 928 is prevented by the body of cement 932,
the housing 940, and the upper cone retainer 944.
The expansion cone 928 preferably has a substantially annular cross
section. The outside diameter of the expansion cone 928 is preferably tapered
to provide a cone shape. The wall thickness of the expansion cone 928 may
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range, for example, from about 0.125 to 3 inches. In a preferred embodiment,
the wall thickness of the expansion cone 928 ranges from about 0.25 to 0.75
inches in order to optimally provide adequate compressive strength with
minimal material. The maximum and minimum outside diameters of the
expansion cone 928 may range, for example, from about 1 to 47 inches. In a
preferred embodiment, the maximum and minimum outside diameters of the
expansion cone 928 range from about 3.5 to 19 in order to optimally provide
expansion of generally available oilfield tubulars
The expansion cone 928 may be fabricated from any number of
conventional commercially available materials such as, for example, ceramic,
tool steel, titanium or low alloy steel. In a preferred embodiment, the
expansion cone 928 is fabricated from tool steel in order to optimally provide
high strength and abrasion resistance. The surface hardness of the outer
surface of the expansion cone 928 may range, for example, from about 50
Rockwell C to 70 Rockwell C. In a preferred embodiment, the surface hardness
of the outer surface of the expansion cone 928 ranges from about 58 Rockwell C
to 62 Rockwell C in order to optimally provide high yield strength. In a
preferred embodiment, the expansion cone 928 is heat treated to optimally
provide a hard outer surface and a resilient interior body in order to
optimally
provide abrasion resistance and fracture toughness.
The lower cone retainer 930 is coupled to the expansion cone 928 and the
housing 940. In a preferred embodiment, axial movement of the expansion
cone 928 is prevented by the lower cone retainer 930. Preferably, the lower
cone retainer 930 has a substantially annular cross-section.
The lower cone retainer 930 may be fabricated from any number of
conventional commercially available materials such as, for example, ceramic,
tool steel, titanium or low alloy steel. In a preferred embodiment, the lower
cone retainer 930 is fabricated from tool steel in order to optimally provide
high
strength and abrasion resistance. The surface hardness of the outer surface of
the lower cone retainer 930 may range, for example, from about 50 Rockwell C
to 70 Rockwell C. In a preferred embodiment, the surface hardness of the outer
surface of the lower cone retainer 930 ranges from about 58 Rockwell C to 62
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Rockwell C in order to optimally provide high yield strength. In a preferred
embodiment, the lower cone retainer 930 is heat treated to optimally provide a
hard outer surface and a resilient interior body in order to optimally provide
abrasion resistance and fracture toughness.
In a preferred embodiment, the lower cone retainer 930 and the
expansion cone 928 are formed as an integral one-piece element in order reduce
the number of components and increase the overall strength of the apparatus.
The outer surface of the lower cone retainer 930 preferably mates with the
inner surfaces of the tubular members 902 and 915.
The body of cement 932 is positioned within the interior of the mandrel
906. The body of cement 932 provides an inner bearing structure for the
mandrel 906. The body of cement 932 further may be easily drilled out using a
conventional drill device. In this manner, the mandrel 906 may be easily
removed using a conventional drilling device.
The body of cement 932 may comprise any number of conventional
commercially available cement compounds. Alternatively, aluminum, cast iron
or some other drillable metallic, composite, or aggregate material may be
substituted for cement. The body of' cement 932 preferably has a substantially
annular cross-section.
The lower guide 934 is coupled to the extension sleeve 936 and housing
940. During operation of the apparatus 900, the lower guide 934 preferably
helps guide the movement of the mandrel 906 within the tubular member 902.
The lower guide 934 preferably has a substantially annular cross-section.
The lower guide 934 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield tubulars, low
alloy steel or stainless steel. In a preferred embodiment, the lower guide 934
is
fabricated from low alloy steel in order to optimally provide high yield
strength.
The outer surface of the lower guide 934 preferably mates with the inner
surface of the tubular member 902 to provide a sliding fit.
The extension sleeve 936 is coupled to the lower guide 934 and the
housing 940. During operation of the apparatus 900, the extension sleeve 936
preferably helps guide the movement of the mandrel 906 within the tubular
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member 902. The extension sleeve 936 preferably has a substantially annular
cross-section.
The extension sleeve 936 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
tubulars, low alloy steel or stainless steel. In a preferred embodiment, the
extension sleeve 936 is fabricated from low alloy steel in order to optimally
provide high yield strength. The outer surface of the extension sleeve 936
preferably mates with the inner surface of the tubular member 902 to provide a
sliding fit. In a preferred embodiment, the extension sleeve 936 and the lower
guide 934 are formed as an integral one-piece element in order to minimize the
number of components and increase the strength of the apparatus.
The spacer 938 is coupled to the sealing sleeve 942. The spacer 938
preferably includes the fluid passage 952 and is adapted to mate with the
extension tube 960 of the shoe 908. In this manner, a plug or dart can be
conveyed from the surface through the fluid passages 918 and 952 into the
fluid
passage 962. Preferably, the spacer 938 has a substantially annular cross-
section.
The spacer 938 may be fabricated from any number of conventional
commercially available materials such as, for example, steel, aluminum or cast
iron. In a preferred embodiment, the spacer 938 is fabricated from aluminum
in order to optimally provide drillability. The end of the spacer 938
preferably
mates with the end of the extension tube 960. In a preferred embodiment, the
spacer 938 and the sealing sleeve 942 are formed as an integral one-piece
element in order to reduce the number of components and increase the strength
of the apparatus.
The housing 940 is coupled to the lower guide 934, extension sleeve 936,
expansion cone 928, body of cement 932, and lower cone retainer 930. During
operation of the apparatus 900, the housing 940 preferably prevents inner
radial motion of the expansion cone 928. Preferably, the housing 940 has a
substantially annular cross-section.
The housing 940 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield tubulars, low
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alloy steel or stainless steel. In a preferred embodiment, the housing 940 is
fabricated from low alloy steel in order to optimally provide high yield
strength.
In a preferred embodiment, the lower guide 934, extension sleeve 936 and
housing 940 are formed as an integral one-piece element in order to minimize
the number of components and increase the strength of the apparatus.
In a particularly preferred embodiment, the interior surface of the
housing 940 includes one or more protrusions to faciliate the connection
between the housing 940 and the body of cement 932.
The sealing sleeve 942 is coupled to the support member 904, the body of
cement 932, the spacer 938, and the upper cone retainer 944. During operation
of the apparatus, the sealing sleeve 942 preferably provides support for the
mandrel 906. The sealing sleeve 942 is preferably coupled to the support
member 904 using the coupling 922. Preferably, the sealing sleeve 942 has a
substantially annular cross-section.
The sealing sleeve 942 may be fabricated from any number of
conventional commercially available materials such as, for example, steel,
aluminum or cast iron. In a preferred embodiment, the sealing sleeve 942 is
fabricated from aluminum in order to optimally provide drillability of the
sealing sleeve 942.
In a particularly preferred embodiment, the outer surface of the sealing
sleeve 942 includes one or more protrusions to faciliate the connection
between
the sealing sleeve 942 and the body of cement 932.
In a particularly preferred embodiment, the spacer 938 and the sealing
sleeve 942 are integrally formed as a one-piece element in order to minimize
the
number of components.
The upper cone retainer 944 is coupled to the expansion cone 928, the
sealing sleeve 942, and the body of cement 932. During operation of the
apparatus 900, the upper cone retainer 944 preferably prevents axial motion of
the expansion cone 928. Preferably, the upper cone retainer 944 has a
substantially annular cross-section.
The upper cone retainer 944 may be fabricated from any number of
conventional commercially available materials such as, for example, steel,
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aluminum or cast iron. In a preferred embodiment, the upper cone retainer 944
is fabricated from aluminum in order to optimally provide drillability of the
upper cone retainer 944.
In a particularly preferred embodiment, the upper cone retainer 944 has
a cross-sectional shape designed to provide increased rigidity. In a
particularly
preferred embodiment, the upper cone retainer 944 has a cross-sectional shape
that is substantially I-shaped to provide increased rigidity and minimize the
amount of material that would have to be drilled out.
The lubricator mandrel 946 is coupled to the retainer 924, the rubber cup
926, the upper cone retainer 944, the lubricator sleeve 948, and the guide
950.
During operation of the apparatus 900, the lubricator mandrel 946 preferably
contains the body of lubricant in the annular region 972 for lubricating the
interface between the mandrel 906 and the tubular member 902. Preferably,
the lubricator mandrel 946 has a substantially annular cross-section.
The lubricator mandrel 946 may be fabricated from any number of
conventional commercially available materials such as, for example, steel,
aluminum or cast iron. In a preferred embodiment, the lubricator mandre1946
is fabricated from aluminum in order to optimally provide drillability of the
lubricator mandrel 946.
The lubricator sleeve 948 is coupled to the lubricator mandrel 946, the
retainer 924, the rubber cup 926, the upper cone retainer 944, the lubricator
sleeve 948, and the guide 950. During operation of the apparatus 900, the
lubricator sleeve 948 preferably supports the rubber cup 926. Preferably, the
lubricator sleeve 948 has a substantially annular cross-section.
The lubricator sleeve 948 may be fabricated from any number of
conventional commercially available materials such as, for example, steel,
aluminum or cast iron. In a preferred embodiment, the lubricator sleeve 948 is
fabricated from aluminum in order to optimally provide drillability of the
lubricator sleeve 948.
As illustrated in Fig. 9c, the lubricator sleeve 948 is supported by the
lubricator mandrel 946. The lubricator sleeve 948 in turn supports the rubber
cup 926. The retainer 924 couples the rubber cup 926 to the lubricator sleeve
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948. In a preferred embodiment, seals 949a and 949b are provided between the
lubricator mandrel 946, lubricator sleeve 948, and rubber cup 926 in order to
optimally seal off the interior region 972 of the tubular member 902.
The guide 950 is coupled to the lubricator mandrel 946, the retainer 924,
and the lubricator sleeve 948. During operation of the apparatus 900, the
guide
950 preferably guides the apparatus on the support member 904. Preferably,
the guide 950 has a substantially annular cross-section.
The guide 950 may be fabricated from any number of conventional
commercially available materials such as, for example, steel, aluminum or cast
iron. In a preferred embodiment, the guide 950 is fabricated from aluminum
order to optimally provide drillability of the guide 950.
The fluid passage 952 is coupled to the mandrel 906. During operation of
the apparatus, the fluid passage 952 preferably conveys hardenable fluidic
materials. In a preferred embodiment, the fluid passage 952 is positioned
about
the centerline of the apparatus 900. In a particularly preferred embodiment,
the fluid passage 952 is adapted to convey hardenable fluidic materials at
pressures and flow rate ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/min in order to optimally provide pressures and flow rates to displace
and circulate fluids during the installation of the apparatus 900.
The various elements of the mandrel 906 may be coupled using any
number of conventional process such as, for example, threaded connections,
welded connections or cementing. In a preferred embodiment, the various
elements of the mandrel 906 are coupled using threaded connections and
cementing.
The shoe 908 preferably includes a housing 954, a body of cement 956, a
sealing sleeve 958, an extension tube 960, a fluid passage 962, and one or
more
outlet jets 964.
The housing 954 is coupled to the body of cement 956 and the lower
portion 914 of the tubular member 902. During operation of the apparatus 900,
the housing 954 preferably couples the lower portion of the tubular member 902
to the shoe 908 to facilitate the extrusion and positioning of the tubular
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member 902. Preferably, the housing 954 has a substantially annular cross-
section.
The housing 954 may be fabricated from any number of conventional
commercially available materials such as, for example, steel or aluminum. In a
preferred embodiment, the housing 954 is fabricated from aluminum in order to
optimally provide drillability of the housing 954.
In a particularly preferred embodiment, the interior surface of the
housing 954 includes one or more protrusions to faciliate the connection
between the body of cement 956 and the housing 954.
The body of cement 956 is coupled to the housing 954, and the sealing
sleeve 958. In a preferred embodiment, the composition of the body of cement
956 is selected to permit the body of cement to be easily drilled out using
conventional drilling machines and processes.
The composition of the body of cement 956 may include any number of
conventional cement compositions. In an alternative embodiment, a drillable
material such as, for example, aluminum or iron may be substituted for the
body of cement 956.
The sealing sleeve 958 is coupled to the body of cement 956, the
extension tube 960, the fluid passage 962, and one or more outlet jets 964.
During operation of the apparatus 900, the sealing sleeve 958 preferably is
adapted to convey a hardenable fluidic material from the fluid passage 952
into
the fluid passage 962 and then into the outlet jets 964 in order to inject the
hardenable fluidic material into an annular region external to the tubular
member 902. In a preferred embodiment, during operation of the apparatus
900, the sealing sleeve 958 further includes an inlet geometry that permits a
conventional plug or dart 974 to become lodged in the inlet of the sealing
sleeve
958. In this manner, the fluid passage 962 may be blocked thereby fluidicly
isolating the interior region 966 of the tubular member 902.
In a preferred embodiment, the sealing sleeve 958 has a substantially
annular cross-section. The sealing sleeve 958 may be fabricated from any
number of conventional commercially available materials such as, for example,
steel, aluminum or cast iron. In a preferred embodiment, the sealing sleeve
958
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is fabricated from aluminum in order to optimally provide drillability of the
sealing sleeve 958.
The extension tube 960 is coupled to the sealing sleeve 958, the fluid
passage 962, and one or more outlet jets 964. During operation of the
apparatus 900, the extension tube 960 preferably is adapted to convey a
hardenable fluidic material from the fluid passage 952 into the fluid passage
962
and then into the outlet jets 964 in order to inject the hardenable fluidic
material into an annular region external to the tubular member 902. In a
preferred embodiment, during operation of the apparatus 900, the sealing
sleeve 960 further includes an inlet geometry that permits a conventional plug
or dart 974 to become lodged in the inlet of the sealing sleeve 958. In this
manner, the fluid passage 962 is blocked thereby fluidicly isolating the
interior
region 966 of the tubular member 902. In a preferred embodiment, one end of
the extension tube 960 mates with one end of the spacer 938 in order to
optimally faciliate the transfer of material between the two.
In a preferred embodiment, the extension tube 960 has a substantially
annular cross-section. The extension tube 960 may be fabricated from any
number of conventional commercially available materials such as, for example,
steel, aluminum or cast iron. In a preferred embodiment, the extension tube
960 is fabricated from aluminum in order to optimally provide drillability of
the
extension tube 960.
The fluid passage 962 is coupled to the sealing sleeve 958, the extension
tube 960, and one or more outlet jets 964. During operation of the apparatus
900, the fluid passage 962 is preferably conveys hardenable fluidic materials.
In
a preferred embodiment, the fluid passage 962 is positioned about the
centerline
of the apparatus 900. In a particularly preferred embodiment, the fluid
passage
962 is adapted to convey hardenable fluidic materials at pressures and flow
rate
ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/min in order to
optimally provide fluids at operationally efficient rates.
The outlet jets 964 are coupled to the sealing sleeve 958, the extension
tube 960, and the fluid passage 962. During operation of the apparatus 900,
the
outlet jets 964 preferably convey hardenable fluidic material from the fluid
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passage 962 to the region exterior of the apparatus 900. In a preferred
embodiment, the shoe 908 includes a plurality of outlet jets 964.
In a preferred embodiment, the outlet jets 964 comprise passages drilled
in the housing 954 and the body of cement 956 in order to simplify the
construction of the apparatus 900.
The various elements of the shoe 908 may be coupled using any number
of conventional process such as, for example, threaded connections, cement or
machined from one piece of material. In a preferred embodiment, the various
elements of the shoe 908 are coupled using cement.
In a preferred embodiment, the assembly 900 is operated substantially as
described above with reference to Figs. 1-8 to create a new section of casing
in a
wellbore or to repair a wellbore casing or pipeline.
In particular, in order to extend a wellbore into a subterranean
formation, a drill string is used in a well known manner to drill out material
from the subterranean formation to form a new section.
The apparatus 900 for forming a wellbore casing in a subterranean
formation is then positioned in the new section of the wellbore. In a
particularly preferred embodiment, the apparatus 900 includes the tubular
member 915. In a preferred embodiment, a hardenable fluidic sealing
hardenable fluidic sealing material is then pumped from a surface location
into
the fluid passage 918. The hardenable fluidic sealing material then passes
from
the fluid passage 918 into the interior region 966 of the tubular member 902
below the mandrel 906. The hardenable fluidic sealing material then passes
from the interior region 966 into the fluid passage 962. The hardenable
fluidic
sealing material then exits the apparatus 900 via the outlet jets 964 and
fills an
annular region between the exterior of the tubular member 902 and the interior
wall of the new section of the wellbore. Continued pumping of the hardenable
fluidic sealing material causes the material to fill up at least a portion of
the
annular region.
The hardenable fluidic sealing material is preferably pumped into the
annular region at pressures and flow rates ranging, for example, from about 0
to 5,000 psi and 0 to 1,500 gallons/min, respectively. In a preferred
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embodiment, the hardenable fluidic sealing material is pumped into the annular
region at pressures and flow rates that are designed for the specific wellbore
section in order to optimize the displacement of the hardenable fluidic
sealing
material while not creating high enough circulating pressures such that
circulation might be lost and that could cause the wellbore to collapse. The
optimum pressures and flow rates are preferably determined using conventional
empirical methods.
The hardenable fluidic sealing material may comprise any number of
conventional commercially available hardenable fluidic sealing materials such
as, for example, slag mix, cement or epoxy. In a preferred embodiment, the
hardenable fluidic sealing material comprises blended cements designed
specifically for the well section being lined available from Halliburton
Energy
Services in Dallas, TX in order to optimally provide support for the new
tubular
member while also maintaining optimal flow characteristics so as to minimize
operational difficulties during the displacement of the cement in the annular
region. The optimum composition of the blended cements is preferably
determined using conventional empirical methods.
The annular region preferably is filled with the hardenable fluidic sealing
material in sufficient quantities to ensure that, upon radial expansion of the
tubular member 902, the annular region of the new section of the wellbore will
be filled with hardenable material.
Once the annular region has been adequately filled with hardenable
fluidic sealing material, a plug or dart 974, or other similar device,
preferably is
introduced into the fluid passage 962 thereby fluidicly isolating the interior
region 966 of the tubular member 902 from the external annular region. In a
preferred embodiment, a non hardenable fluidic material is then pumped into
the interior region 966 causing the interior region 966 to pressurize. In a
particularly preferred embodiment, the plug or dart 974, or other similar
device,
preferably is introduced into the fluid passage 962 by introducing the plug or
dart 974, or other similar device into the non hardenable fluidic material. In
this manner, the amount of cured material within the interior of the tubular
members 902 and 915 is minimized.
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Once the interior region 966 becomes sufficiently pressurized, the
tubular members 902 and 915 are extruded off of the mandre1906. The
mandre1906 may be fixed or it may be expandible. During the extrusion
process, the mandrel 906 is raised out of the expanded portions of the tubular
members 902 and 915 using the support member 904. During this extrusion
process, the shoe 908 is preferably substantially stationary.
The plug or dart 974 is preferably placed into the fluid passage 962 by
introducing the plug or dart 974 into the fluid passage 918 at a surface
location
in a conventional manner. The plug or dart 974 may comprise any number of
conventional commercially available devices for 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 a preferred embodiment, the plug or
dart 974 comprises a MSChatch-down plug available from Halliburton Energy
Services in Dallas, TX.
After placement of the plug or dart 974 in the fluid passage 962, the non
hardenable fluidic inaterial is preferably pumped into the interior region 966
at
pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to
3,000 gallons/min in order to optimally extrude the tubular members 902 and
915 off of the mandre1906.
For typical tubular members 902 and 915, the extrusion of the tubular
members 902 and 915 off of the expandable mandrel will begin when the
pressure of the interior region 966 reaches approximately 500 to 9,000 psi. In
a
preferred embodiment, the extrusion of the tubular members 902 and 915 off
of the mandrel 906 begins when the pressure of the interior region 966 reaches
approximately 1,200 to 8,500 psi with a flow rate of about 40 to 1250
gallons/minute.
During the extrusion process, the mandrel 906 may be raised out of the
expanded portions of the tubular members 902 and 915 at rates ranging, for
example, from about 0 to 5 ft/sec. In a preferred embodiment, during the
extrusion process, the mandrel 906 is raised out of the expanded portions of
the
tubular members 902 and 915 at rates ranging from about 0 to 2 ft/sec in order
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to optimally provide pulling speed fast enough to permit efficient operation
and
permit full expansion of the tubular members 902 and 915 prior to curing of
the
hardenable fluidic sealing material; but not so fast that timely adjustment of
operating parameters during operation is prevented.
When the upper end portion of the tubular member 915 is extruded off of
the mandrel 906, the outer surface of the upper end portion of the tubular
member 915 will preferably contact the interior surface of the lower end
portion
of the existing casing 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 a preferred embodiment, the contact pressure of the
overlapping joint between the upper end of the tubular member 915 and the
existing section of wellbore casing ranges from approximately 400 to 10,000
psi
in order to optimally provide contact pressure to activate the sealing members
and provide optimal resistance such that the tubular member 915 and existing
wellbore casing will carry typical tensile and compressive loads.
In a preferred embodiment, the operating pressure and flow rate of the
non hardenable fluidic material will be controllably ramped down when the
mandre1906 reaches the upper end portion of the tubular member 915. In this
manner, the sudden release of pressure caused by the complete extrusion of the
tubular member 915 off of the expandable mandre1906 can be minimized. In a
preferred 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 mandrel 906 has completed approximately all but about the
last 5 feet of the extrusion process.
In an alternative preferred embodiment, the operating pressure and/or
flow rate of the hardenable fluidic sealing material and/or the non hardenable
fluidic material are controlled during all phases of the operation of the
apparatus 900 to minimize shock.
Alternatively, or in combination, a shock absorber is provided in the
support member 904 in order to absorb the shock caused by the sudden release
of pressure.
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Alternatively, or in combination, a mandrel catching structure is
provided above the support member 904 in order to catch or at least decelerate
the mandre1906.
Once the extrusion process is completed, the mandre1906 is removed
from the wellbore. In a preferred embodiment, either before or after the
removal of the mandrel 906, the integrity of the fluidic seal of the
overlapping
joint between the upper portion of the tubular member 915 and the lower
portion of the existing casing is tested using conventional methods. If the
fluidic seal of the overlapping joint between the upper portion of the tubular
member 915 and the lower portion of the existing casing is satisfactory, then
the uncured portion of any of the hardenable fluidic sealing material within
the
expanded tubular member 915 is then removed in a conventional manner. The
hardenable fluidic sealing material within the annular region between the
expanded tubular member 915 and the existing casing and new section of
wellbore is then allowed to cure.
Preferably any remaining cured hardenable fluidic sealing material
within the interior of the expanded tubular members 902 and 915 is then
removed in a conventional manner using a conventional drill string. The
resulting new section of casing preferably includes the expanded tubular
members 902 and 915 and an outer annular layer of cured hardenable fluidic
sealing material. The bottom portion of the apparatus 900 comprising the shoe
908 may then be removed by drilling out the shoe 908 using conventional
drilling methods.
In an alternative embodiment, during the extrusion process, it may be
necessary to remove the entire apparatus 900 from the interior of the wellbore
due to a malfunction. In this circumstance, a conventional drill string is
used
to drill out the interior sections of the apparatus 900 in order to facilitate
the
removal of the remaining sections. In a preferred embodiment, the interior
elements of the apparatus 900 are fabricated from materials such as, for
example, cement and aluminum, that permit a conventional drill string to be
employed to drill out the interior components.
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In particular, in a preferred embodiment, the composition of the interior
sections of the mandrel 906 and shoe 908, including one or more of the body of
cement 932, the spacer 938, the sealing sleeve 942, the upper cone retainer
944,
the lubricator mandrel 946, the lubricator sleeve 948, the guide 950, the
housing 954, the body of cement 956, the sealing sleeve 958, and the extension
tube 960, are selected to permit at least some of these components to be
drilled
out using conventional drilling methods and apparatus. In this manner, in the
event of a malfunction downhole, the apparatus 900 may be easily removed
from the wellbore.
Referring now to Figs. 10a, lOb, 10c, 10d, 10e, 10f, and lOg a method and
apparatus for creating a tie-back liner in a wellbore will now be described.
As
illustrated in Fig. 10a, a wellbore 1000 positioned in a subterranean
formation
1002 includes a first casing 1004 and a second casing 1006.
The first casing 1004 preferably includes a tubular liner 1008 and a
cement annulus 1010. The second casing 1006 preferably includes a tubular
liner 1012 and a cement annulus 1014. In a preferred embodiment, the second
casing 1006 is formed by expanding a tubular member substantially as
described above with reference to Figs. 1-9c or below with reference to Figs.
11a-11f.
In a particularly preferred embodiment, an upper portion of the tubular
liner 1012 overlaps with a lower portion of the tubular liner 1008. In a
particularly preferred embodiment, an outer surface of the upper portion of
the
tubular liner 1012 includes one or more sealing members 1016 for providing a
fluidic seal between the tubular liners 1008 and 1012.
Referring to Fig. lOb, in order to create a tie-back liner that extends from
the overlap between the first and second casings, 1004 and 1006, an apparatus
1100 is preferably provided that includes an expandable mandrel or pig 1105, a
tubular member 1110, a shoe 1115, one or more cup seals 1120, a fluid passage
1130, a fluid passage 1135, one or more fluid passages 1140, seals 1145, and a
support member 1150.
The expandable mandrel or pig 1105 is coupled to and supported by the
support member 1150. The expandable mandrel 1105 is preferably adapted to
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controllably expand in a radial direction. The expandable mandrel 1105 may
comprise any number of conventional commercially available expandable
mandrels modified in accordance with the teachings of the present disclosure.
In a preferred embodiment, the expandable mandrel 1105 comprises a hydraulic
expansion tool substantially as disclosed in U.S. Pat. No. 5,348,095, the
disclosure of which is incorporated herein by reference, modified in
accordance
with the teachings of the present disclosure.
The tubular member 1110 is coupled to and supported by the expandable
mandrel 1105. The tubular member 1105 is expanded in the radial direction
and extruded off of the expandable mandrel 1105. The tubular member 1110
may be fabricated from any number of materials such as, for example, Oilfield
Country Tubular Goods, 13 chromium tubing or plastic piping. In a preferred
embodiment, the tubular member 1110 is fabricated from Oilfield Country
Tubular Goods.
The inner and outer diameters of the tubular member 1110 may range,
for example, from approximately 0.75 to 47 inches and 1.05 to 48 inches,
respectively. In a preferred embodiment, the inner and outer diameters of the
tubular member 1110 range from about 3 to 15.5 inches and 3.5 to 16 inches,
respectively in order to optimally provide coverage for typical oilfield
casing
sizes. The tubular member 1110 preferably comprises a solid member.
In a preferred embodiment, the upper end portion of the tubular member
1110 is slotted, perforated, or otherwise modified to catch or slow down the
mandrel 1105 when it completes the extrusion of tubular member 1110. In a
preferred embodiment, the length of the tubular member 1110 is limited to
minimize the possibility of buckling. For typical tubular member 1110
materials, the length of the tubular member 1110 is preferably limited to
between about 40 to 20,000 feet in length.
The shoe 1115 is coupled to the expandable mandrel 1105 and the
tubular member 1110. The shoe 1115 includes the fluid passage 1135. The
shoe 1115 may comprise 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
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accordance with the teachings of the present disclosure. In a preferred
embodiment, the shoe 1115 comprises an aluminum down-jet guide shoe with a
sealing sleeve for a latch-down plug with side ports radiating off of the exit
flow
port available from Halliburton Energy Services in Dallas, TX, modified in
accordance with the teachings of the present disclosure, in order to optimally
guide the tubular member 1100 to the overlap between the tubular member
1100 and the casing 1012, optimally fluidicly isolate the interior of the
tubular
member 1100 after the latch down plug has seated, and optimally permit
drilling out of the shoe 1115 after completion of the expansion and cementing
operations.
In a preferred embodiment, the shoe 1115 includes one or more side
outlet ports 1140 in fluidic communication with the fluid passage 1135. In
this
manner, the shoe 1115 injects hardenable fluidic sealing material into the
region outside the shoe 1115 and tubular member 1110. In a preferred
embodiment, the shoe 1115 includes one or more of the fluid passages 1140 each
having an inlet geometry that can receive a dart and/or a ball sealing member.
In this manner, the fluid passages 1140 can be sealed off by introducing a
plug,
dart and/or ball sealing elements into the fluid passage 1130.
The cup seal 1120 is coupled to and supported by the support member
1150. The cup seal 1120 prevents foreign materials from entering the interior
region of the tubular member 1110 adjacent to the expandable mandrel 1105.
The cup seal 1120 may comprise 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 a preferred embodiment, the cup seal 1120 comprises a SIP cup, available
from Halliburton Energy Services in Dallas, TX in order to optimally provide a
barrier to debris and contain a body of lubricant.
The fluid passage 1130 permits fluidic materials to be transported to and
from the interior region of the tubular member 1110 below the expandable
mandrel 1105. The fluid passage 1130 is coupled to and positioned within the
support member 1150 and the expandable mandrel 1105. The fluid passage
1130 preferably extends from a position adjacent to the surface to the bottom
of
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the expandable mandrel 1105. The fluid passage 1130 is preferably positioned
along a centerline of the apparatus 1100. The fluid passage 1130 is preferably
selected to transport materials such as cement, drilling mud or epoxies at
flow
rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to
9,000 psi in order to optimally provide sufficient operating pressures to
circulate fluids at operationally efficient rates.
The fluid passage 1135 permits fluidic materials to be transmitted from
fluid passage 1130 to the interior of the tubular member 1110 below the
mandrel 1105.
The fluid passages 1140 permits fluidic materials to be transported to
and from the region exterior to the tubular member 1110 and shoe 1115. The
fluid passages 1140 are coupled to and positioned within the shoe 1115 in
fluidic
communication with the interior region of the tubular member 1110 below the
expandable mandrel 1105. The fluid passages 1140 preferably have a cross-
sectional shape that permits a plug, or other similar device, to be placed in
the
fluid passages 1140 to thereby block further passage of fluidic materials. In
this
manner, the interior region of the tubular member 1110 below the expandable
mandrel 1105 can be fluidicly isolated from the region exterior to the tubular
member 1105. This permits the interior region of the tubular member 1110
below the expandable mandrel 1105 to be pressurized.
The fluid passages 1140 are preferably positioned along the periphery of
the shoe 1115. The fluid passages 1140 are preferably selected to convey
materials such as cement, drilling mud or epoxies at flow rates and pressures
ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in order to
optimally fill the annular region between the tubular member 1110 and the
tubular liner 1008 with fluidic materials. In a preferred embodiment, the
fluid
passages 1140 include an inlet geometry that can receive a dart and/or a ball
sealing member. In this manner, the fluid passages 1140 can be sealed off by
introducing a plug, dart and/or ball sealing elements into the fluid passage
1130. In a preferred embodiment, the apparatus 1100 includes a plurality of
fluid passage 1140.
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In an alternative embodiment, the base of the shoe 1115 includes a single
inlet passage coupled to the fluid passages 1140 that is adapted to receive a
plug, or other similar device, to permit the interior region of the tubular
member 1110 to be fluidicly isolated from the exterior of the tubular member
1110.
The seals 1145 are coupled to and supported by a lower end portion of
the tubular member 1110. The seals 1145 are further positioned on an outer
surface of the lower end portion of the tubular member 1110. The seals 1145
permit the overlapping joint between the upper end portion of the casing 1012
and the lower end portion of the tubular member 1110 to be fluidicly sealed.
The seals 1145 may comprise 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 a preferred
embodiment, the seals 1145 comprise seals molded from Stratalock epoxy
available from Halliburton Energy Services in Dallas, TX in order to optimally
provide a hydraulic seal in the overlapping joint and optimally provide load
carrying capacity to withstand the range of typical tensile and compressive
loads.
In a preferred embodiment, the seals 1145 are selected to optimally
provide a sufficient frictional force to support the expanded tubular member
1110 from the tubular liner 1008. In a preferred embodiment, the frictional
force provided by the seals 1145 ranges from about 1,000 to 1,000,0001bf in
tension and compression in order to optimally support the expanded tubular
member 1110.
The support member 1150 is coupled to the expandable mandrel 1105,
tubular member 1110, shoe 1115, and seal 1120. The support member 1150
preferably comprises an annular member having sufficient strength to carry the
apparatus 1100 into the wellbore 1000. In a preferred embodiment, the support
member 1150 further includes one or more conventional centralizers (not
illustrated) to help stabilize the tubular member 1110.
In a preferred embodiment, a quantity of lubricant 1150 is provided in
the annular region above the expandable mandrel 1105 within the interior of
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the tubular member 1110. In this manner, the extrusion of the tubular
member 1110 off of the expandable mandrel 1105 is facilitated. The lubricant
1150 may comprise any number of conventional commercially available
lubricants such as, for example, Lubriplate, chlorine based lubricants or
Climax
1500 Antiseize (3100). In a preferred embodiment, the lubricant 1150
comprises Climax 1500 Antiseize (3100) available from Climax Lubricants and
Equipment Co. in Houston, TX in order to optimally provide lubrication for the
extrusion process.
In a preferred embodiment, the support member 1150 is thoroughly
cleaned prior to assembly to the remaining portions of the apparatus 1100. In
this manner, the introduction of foreign material into the apparatus 1100 is
minimized. This minimizes the possibility of foreign material clogging the
various flow passages and valves of the apparatus 1100 and to ensure that no
foreign material interferes with the expansion mandrel 1105 during the
extrusion process.
In a particularly preferred embodiment, the apparatus 1100 includes a
packer 1155 coupled to the bottom section of the shoe 1115 for fluidicly
isolating the region of the wellbore 1000 below the apparatus 1100. In this
manner, fluidic materials are prevented from entering the region of the
wellbore 1000 below the apparatus 1100. The packer 1155 may comprise any
number of conventional commercially available packers such as, for example,
EZ Drill Packei' EZ SV Packer or a drillable cement retainer. In a preferred
embodiment, the packer 1155 comprises an EZ Drill Packei*available from
Halliburton Energy Services in Dallas, TX. In an alternative embodiment, a
high gel strength piIl may be set below the tie-back in place of the packer
1155.
In another alternative embodiment, the packer 1155 may be omitted.
In a preferred embodiment, before or after positioning the apparatus
1100 within the wellbore 1100, a couple of wellbore volumes are circulated in
order to ensure that no foreign materials are located within the wellbore 1000
that might clog up the various flow passages and valves of the apparatus 1100
and to ensure that no foreign material interferes with the operation of the
expansion mandrel 1105.
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As illustrated in Fig. 10c, a hardenable fluidic sealing material 1160 is
then pumped from a surface location into the fluid passage 1130. The material
1160 then passes from the fluid passage 1130 into the interior region of the
tubular member 1110 below the expandable mandrel 1105. The material 1160
then passes from the interior region of the tubular member 1110 into the fluid
passages 1140. The material 1160 then exits the apparatus 1100 and fills the
annular region between the exterior of the tubular member 1110 and the
interior wall of the tubular liner 1008. Continued pumping of the material
1160
causes the material 1160 to fill up at least a portion of the annular region.
The material 1160 may be pumped into the annular region at pressures
and flow rates ranging, for example, from about 0 to 5,000 psi and 0 to 1,500
gallons/min, respectively. In a preferred embodiment, the material 1160 is
pumped into the annular region at pressures and flow rates specifically
designed for the casing sizes being run, the annular spaces being filled, the
pumping equipment available, and the properties of the fluid being pumped.
The optimum flow rates and pressures are preferably calculated using
conventional empirical methods.
The hardenable fluidic sealing material 1160 may comprise any number
of conventional commercially available hardenable fluidic sealing materials
such
as, for example, slag mix, cement or epoxy. In a preferred embodiment, the
hardenable fluidic sealing material 1160 comprises blended cements
specifically
designed for well section being tied-back, available from Halliburton Energy
Services in Dallas, TX in order to optimally provide proper support for the
tubular member 1110 while maintaining optimum flow characteristics so as to
minimize operational difficulties during the displacement of cement in the
annular region. The optimum blend of the blended cements are preferably
determined using conventional empirical methods.
The annular region may be filled with the material 1160 in sufficient
quantities to ensure that, upon radial expansion of the tubular member 1110,
the annular region will be filled with material 1160.
As illustrated in Fig. lOd, once the annular region has been adequately
filled with material 1160, one or more plugs 1165, or other similar devices,
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preferably are introduced into the fluid passages 1140 thereby fluidicly
isolating
the interior region of the tubular member 1110 from the annular region
external to the tubular member 1110. In a preferred embodiment, a non
hardenable fluidic material 1161 is then pumped into the interior region of
the
tubular member 1110 below the mandrel 1105 causing the interior region to
pressurize. In a particularly preferred embodiment, the one or more plugs
1165, or other similar devices, are introduced into the fluid passage 1140
with
the introduction of the non hardenable fluidic material. In this manner, the
amount of hardenable fluidic material within the interior of the tubular
member 1110 is minimized.
As illustrated in Fig. 10e, once the interior region becomes sufficiently
pressurized, the tubular member 1110 is extruded off of the expandable
mandrel 1105. During the extrusion process, the expandable mandrel 1105 is
raised out of the expanded portion of the tubular member 1110.
The plugs 1165 are preferably placed into the fluid passages 1140 by
introducing the plugs 1165 into the fluid passage 1130 at a surface location
in a
conventional manner. The plugs 1165 may comprise any number of
conventional commercially available devices from plugging a fluid passage such
as, for example, brass balls, plugs, rubber balls, or darts modified in
accordance
with the teachings of the present disclosure.
In a preferred embodiment, the plugs 1165 comprise low density rubber
balls. In an alternative embodiment, for a shoe 1105 having a common central
inlet passage, the plugs 1165 comprise a single latch down dart.
After placement of the plugs 1165 in the fluid passages 1140, the non
hardenable fluidic material 1161 is preferably pumped into the interior region
of the tubular member 1110 below the mandrel 1105 at pressures and flow rates
ranging from approximately 500 to 9,000 psi and 40 to 3,000 gallons/min.
In a preferred embodiment, after placement of the plugs 1165 in the fluid
passages 1140, the non hardenable fluidic material 1161 is preferably pumped
into the interior region of the tubular member 1110 below the mandrel 1105 at
pressures and flow rates ranging from approximately 1200 to 8500 psi and 40 to
1250 gallons/min in order to optimally provide extrusion of typical tubulars.
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For typical tubular members 1110, the extrusion of the tubular member
1110 off of the expandable mandrel 1105 will begin when the pressure of the
interior region of the tubular member 1110 below the mandrel 1105 reaches, for
example, approximately 1200 to 8500 psi. In a preferred embodiment, the
extrusion of the tubular member 1110 off of the expandable mandrel 1105
begins when the pressure of the interior region of the tubular member 1110
below the mandrel 1105 reaches approximately 1200 to 8500 psi.
During the extrusion process, the expandable mandrel 1105 may be
raised out of the expanded portion of the tubular member 1110 at rates
ranging,
for example, from about 0 to 5 ft/sec. In a preferred embodiment, during the
extrusion process, the expandable mandrel 1105 is raised out of the expanded
portion of the tubular member 1110 at rates ranging from about 0 to 2 ft/sec
in
order to optimally provide permit adjustment of operational parameters, and
optimally ensure that the extrusion process will be completed before the
material 1160 cures.
In a preferred embodiment, at least a portion 1180 of the tubular
member 1110 has an internal diameter less than the outside diameter of the
mandrel 1105. In this manner, when the mandrel 1105 expands the section
1180 of the tubular member 1110, at least a portion of the expanded section
1180 effects a seal with at least the wellbore casing 1012. In a particularly
preferred embodiment, the seal is effected by compressing the seals 1016
between the expanded section 1180 and the wellbore casing 1012. In a
preferred embodiment, the contact pressure of the joint between the expanded
section 1180 of the tubular member 1110 and the casing 1012 ranges from
about 500 to 10,000 psi in order to optimally provide pressure to activate the
sealing members 1145 and provide optimal resistance to ensure that the joint
will withstand typical extremes of tensile and compressive loads.
In an alternative preferred embodiment, substantially all of the entire
length of the tubular member 1110 has an internal diameter less than the
outside diameter of the mandrel 1105. In this manner, extrusion of the tubular
member 1110 by the mandrel 1105 results in contact between substantially all
of the expanded tubular member 1110 and the existing casing 1008. In a
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preferred embodiment, the contact pressure of the joint between the expanded
tubular member 1110 and the casings 1008 and 1012 ranges from about 500 to
10,000 psi in order to optimally provide pressure to activate the sealing
members 1145 and provide optimal resistance to ensure that the joint will
withstand typical extremes of tensile and compressive loads.
In a preferred embodiment, the operating pressure and flow rate of the
material 1161 is controllably ramped down when the expandable mandrel 1105
reaches the upper end portion of the tubular member 1110. In this manner, the
sudden release of pressure caused by the complete extrusion of the tubular
member 1110 off of the expandable mandrel 1105 can be minimized. In a
preferred embodiment, the operating pressure of the fluidic material 1161 is
reduced in a substantially linear fashion from 100% to about 10% during the
end of the extrusion process beginning when the mandrel 1105 has completed
approximately all but about 5 feet of the extrusion process.
Alternatively, or in combination, a shock absorber is provided in the
support member 1150 in order to absorb the shock caused by the sudden release
of pressure.
Alternatively, or in combination, a mandrel catching structure is
provided in the upper end portion of the tubular member 1110 in order to catch
or at least decelerate the mandrel 1105.
Referring to Fig. 10f, once the extrusion process is completed, the
expandable mandrel 1105 is removed from the wellbore 1000. In a preferred
embodiment, either before or after the removal of the expandable mandrel
1105, the integrity of the fluidic seal of the joint between the upper portion
of
the tubular member 1110 and the upper portion of the tubular liner 1108 is
tested using conventional methods. If the fluidic seal of the joint between
the
upper portion of the tubular member 1110 and the upper portion of the tubular
liner 1008 is satisfactory, then the uncured portion of the material 1160
within
the expanded tubular member 1110 is then removed in a conventional manner.
The material 1160 within the annular region between the tubular member 1110
and the tubular liner 1008 is then allowed to cure.
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As illustrated in Fig. lOf, preferably any remaining cured material 1160
within the interior of the expanded tubular member 1110 is then removed in a
conventional manner using a conventional drill string. The resulting tie-back
liner of casing 1170 includes the expanded tubular member 1110 and an outer
annular layer 1175 of cured material 1160.
As illustrated in Fig. 10g, the remaining bottom portion of the apparatus
1100 comprising the shoe 1115 and packer 1155 is then preferably removed by
drilling out the shoe 1115 and packer 1155 using conventional drilling
methods.
In a particularly preferred embodiment, the apparatus 1100 incorporates
the apparatus 900.
Referring now to Figs. lla-l lf, an embodiment of an apparatus and
method for hanging a tubular liner off of an existing wellbore casing will now
be described. As illustrated in Fig. l la, a wellbore 1200 is positioned in a
subterranean formation 1205. The wellbore 1200 includes an existing cased
section 1210 having a tubular casing 1215 and an annular outer layer of cement
1220.
In order to extend the wellbore 1200 into the subterranean formation
1205, a drill string 1225 is used in a well known manner to drill out material
from the subterranean formation 1205 to form a new section 1230.
As illustrated in Fig. l lb, an apparatus 1300 for forming a wellbore
casing in a subterranean formation is then positioned in the new section 1230
of the wellbore 100. The apparatus 1300 preferably includes an expandable
mandrel or pig 1305, a tubular member 1310, a shoe 1315, a fluid passage 1320,
a fluid passage 1330, a fluid passage 1335, seals 1340, a support member 1345,
and a wiper plug 1350.
The expandable mandrel 1305 is coupled to and supported by the support
member 1345. The expandable mandrel 1305 is preferably adapted to
controllably expand in a radial direction. The expandable mandrel 1305 may
comprise any number of conventional commercially available expandable
mandrels modified in accordance with the teachings of the present disclosure.
In a preferred embodiment, the expandable mandrel 1305 comprises a hydraulic
expansion tool substantially as disclosed in U.S. Pat. No. 5,348,095, the
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disclosure of which is incorporated herein by reference, modified in
accordance
with the teachings of the present disclosure.
The tubular member 1310 is coupled to and supported by the expandable
mandrel 1305. The tubular member 1310 is preferably expanded in the radial
direction and extruded off of the expandable mandrel 1305. The tubular
member 1310 may be fabricated from any number of materials such as, for
example, Oilfield Country Tubular Goods (OCTG), 13 chromium steel
tubing/casing or plastic casing. In a preferred embodiment, the tubular
member 1310 is fabricated from OCTG. The inner and outer diameters of the
tubular member 1310 may range, for example, from approximately 0.75 to 47
inches and 1.05 to 48 inches, respectively. In a preferred embodiment, the
inner and outer diameters of the tubular member 1310 range from about 3 to
15.5 inches and 3.5 to 16 inches, respectively in order to optimally provide
minimal telescoping effect in the most commonly encountered wellbore sizes.
In a preferred embodiment, the tubular member 1310 includes an upper
portion 1355, an intermediate portion 1360, and a lower portion 1365. In a
preferred embodiment, the wall thickness and outer diameter of the upper
portion 1355 of the tubular member 1310 range from about 3/8 to 1 1/2 inches
and 3 1/2 to 16 inches, respectively. In a preferred embodiment, the wall
thickness and outer diameter of the intermediate portion 1360 of the tubular
member 1310 range from about 0.625 to 0.75 inches and 3 to 19 inches,
respectively. In a preferred embodiment, the wall thickness and outer
diameter of the lower portion 1365 of the tubular member 1310 range from
about 3/8 to 1.5 inches and 3.5 to 16 inches, respectively.
In a particularly preferred embodiment, the outer diameter of the lower
portion 1365 of the tubular member 1310 is significantly less than the outer
diameters of the upper and intermediate portions, 1355 and 1360, of the
tubular
member 1310 in order to optimize the formation of a concentric and
overlapping arrangement of wellbore casings. In this manner, as will be
described below with reference to Figs. 12 and 13, a wellhead system is
optimally provided. In a preferred embodiment, the formation of a wellhead
system does not include the use of a hardenable fluidic material.
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In a particularly preferred embodiment, the wall thickness of the
intermediate section 1360 of the tubular member 1310 is less than or equal to
the wall thickness of the upper and lower sections, 1355 and 1365, of the
tubular member 1310 in order to optimally faciliate the initiation of the
extrusion process and optimally permit the placement of the apparatus in areas
of the wellbore having tight clearances.
The tubular member 1310 preferably comprises a solid member. In a
preferred embodiment, the upper end portion 1355 of the tubular member 1310
is slotted, perforated, or otherwise modified to catch or slow down the
mandrel
1305 when it completes the extrusion of tubular member 1310. In a preferred
embodiment, the length of the tubular member 1310 is limited to minimize the
possibility of buckling. For typical tubular member 1310 materials, the length
of the tubular member 1310 is preferably limited to between about 40 to 20,000
feet in length.
The shoe 1315 is coupled to the tubular member 1310. The shoe 1315
preferably includes fluid passages 1330 and 1335. The shoe 1315 may comprise
any number of conventional commercially available shoes such as, for example,
Super Seal II float shoe, Super Seal II Down-Jet float shoe or guide shoe with
a
sealing sleeve for a latch-down plug modified in accordance with the teachings
of the present disclosure. In a preferred embodiment, the shoe 1315 comprises
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 tubular member 1310 into the wellbore 1200, optimally fluidicly
isolate the interior of the tubular member 1310, and optimally permit the
complete drill out of the shoe 1315 upon the completion of the extrusion and
cementing operations.
In a preferred embodiment, the shoe 1315 further includes one or more
side outlet ports in fluidic communication with the fluid passage 1330. In
this
manner, the shoe 1315 preferably injects hardenable fluidic sealing material
into the region outside the shoe 1315 and tubular member 1310. In a preferred
embodiment, the shoe 1315 includes the fluid passage 1330 having an inlet
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geometry that can receive a fluidic sealing member. In this manner, the fluid
passage 1330 can be sealed off by introducing a plug, dart and/or ball sealing
elements into the fluid passage 1330.
The fluid passage 1320 permits fluidic materials to be transported to and
from the interior region of the tubular member 1310 below the expandable
mandrel 1305. The fluid passage 1320 is coupled to and positioned within the
support member 1345 and the expandable mandrel 1305. The fluid passage
1320 preferably extends from a position adjacent to the surface to the bottom
of
the expandable mandrel 1305. The fluid passage 1320 is preferably positioned
along a centerline of the apparatus 1300. The fluid passage 1320 is preferably
selected to transport materials such as cement, drilling mud, or epoxies at
flow
rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to
9,000 psi in order to optimally provide sufficient operating pressures to
circulate fluids at operationally efficient rates.
The fluid passage 1330 permits fluidic materials to be transported to and
from the region exterior to the tubular member 1310 and shoe 1315. The fluid
passage 1330 is coupled to and positioned within the shoe 1315 in fluidic
communication with the interior region 1370 of the tubular member 1310 below
the expandable mandrel 1305. The fluid passage 1330 preferably has a cross-
sectional shape that permits a plug, or other similar device, to be placed in
fluid
passage 1330 to thereby block further passage of fluidic materials. In this
manner, the interior region 1370 of the tubular member 1310 below the
expandable mandrel 1305 can be fluidicly isolated from the region exterior to
the tubular member 1310. This permits the interior region 1370 of the tubular
member 1310 below the expandable mandrel 1305 to be pressurized. The fluid
passage 1330 is preferably positioned substantially along the centerline of
the
apparatus 1300.
The fluid passage 1330 is preferably selected to convey materials such as
cement, drilling mud or epoxies at flow rates and pressures ranging from about
0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the
annular region between the tubular member 1310 and the new section 1230 of
the wellbore 1200 with fluidic materials. In a preferred embodiment, the fluid
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passage 1330 includes an inlet geometry that can receive a dart and/or a ball
sealing member. In this manner, the fluid passage 1330 can be sealed off by
introducing a plug, dart and/or ball sealing elements into the fluid passage
1320.
The fluid passage 1335 permits fluidic materials to be transported to and
from the region exterior to the tubular member 1310 and shoe 1315. The fluid
passage 1335 is coupled to and positioned within the shoe 1315 in fluidic
communication with the fluid passage 1330. The fluid passage 1335 is
preferably positioned substantially along the centerline of the apparatus
1300.
The fluid passage 1335 is preferably selected to convey materials such as
cement, drilling mud or epoxies at flow rates and pressures ranging from about
0 to 3,000 gallons/minute and 0 to 9,000 psi in order to optimally fill the
annular region between the tubular member 1310 and the new section 1230 of
the wellbore 1200 with fluidic materials.
The seals 1340 are coupled to and supported by the upper end portion
1355 of the tubular member 1310. The seals 1340 are further positioned on an
outer surface of the upper end portion 1355 of the tubular member 1310. The
seals 1340 permit the overlapping joint between the lower end portion of the
casing 1215 and the upper portion 1355 of the tubular member 1310 to be
fluidicly sealed. The seals 1340 may comprise 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
a
preferred embodiment, the seals 1340 comprise seals molded from Stratalock
epoxy available from Halliburton Energy Services in Dallas, TX in order to
optimally provide a hydraulic seal in the annulus of the overlapping joint
while
also creating optimal load bearing capability to withstand typical tensile and
compressive loads.
In a preferred embodiment, the seals 1340 are selected to optimally
provide a sufficient frictional force to support the expanded tubular member
1310 from the existing casing 1215. In a preferred embodiment, the frictional
force provided by the seals 1340 ranges from about 1,000 to 1,000,000 lbf in
order to optimally support the expanded tubular member 1310.
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The support member 1345 is coupled to the expandable mandrel 1305,
tubular member 1310, shoe 1315, and seals 1340. The support member 1345
preferably comprises an annular member having sufficient strength to carry the
apparatus 1300 into the new section 1230 of the wellbore 1200. In a preferred
embodiment, the support member 1345 further includes one or more
conventional centralizers (not illustrated) to help stabilize the tubular
member
1310.
In a preferred embodiment, the support member 1345 is thoroughly
cleaned prior to assembly to the remaining portions of the apparatus 1300. In
this manner, the introduction of foreign material into the apparatus 1300 is
minimized. This minimizes the possibility of foreign material clogging the
various flow passages and valves of the apparatus 1300 and to ensure that no
foreign material interferes with the expansion process.
The wiper plug 1350 is coupled to the mandrel 1305 within the interior
region 1370 of the tubular member 1310. The wiper plug 1350 includes a fluid
passage 1375 that is coupled to the fluid passage 1320. The wiper plug 1350
may comprise one or more conventional commercially available wiper plugs
such as, for example, Multiple Stage Cementer latch-down plugs, Omega latch-
down plugs or three-wiper latch-down plug modified in accordance with the
teachings of the present disclosure. In a preferred embodiment, the wiper plug
1350 comprises a Multiple Stage Cementer latch-down plug available from
Halliburton Energy Services in Dallas, TX modified in a conventional manner
for releasable attachment to the expansion mandrel 1305.
In a preferred embodiment, before or after positioning the apparatus
1300 within the new section 1230 of the wellbore 1200, a couple of wellbore
volumes are circulated in order to ensure that no foreign materials are
located
within the wellbore 1200 that might clog up the various flow passages and
valves of the apparatus 1300 and to ensure that no foreign material interferes
with the extrusion process.
As illustrated in Fig. 11c, a hardenable fluidic sealing material 1380 is
then pumped from a surface location into the fluid passage 1320. The material
1380 then passes from the fluid passage 1320, through the fluid passage 1375,
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and into the interior region 1370 of the tubular member 1310 below the
expandable mandrel 1305. The material 1380 then passes from the interior
region 1370 into the fluid passage 1330. The material 1380 then exits the
apparatus 1300 via the fluid passage 1335 and fills the annular region 1390
between the exterior of the tubular member 1310 and the interior wall of the
new section 1230 of the wellbore 1200. Continued pumping of the material
1380 causes the material 1380 to fill up at least a portion of the annular
region
1390.
The material 1380 may be pumped into the annular region 1390 at
pressures and flow rates ranging, for example, from about 0 to 5000 psi and 0
to
1,500 gallons/min, respectively. In a preferred embodiment, the material 1380
is pumped into the annular region 1390 at pressures and flow rates ranging
from about 0 to 5000 psi and 0 to 1,500 gallons/min, respectively, in order to
optimally fill the annular region between the tubular member 1310 and the new
section 1230 of the wellbore 1200 with the hardenable fluidic sealing material
1380.
The hardenable fluidic sealing material 1380 may comprise any number
of conventional commercially available hardenable fluidic sealing materials
such
as, for example, slag mix, cement or epoxy. In a preferred embodiment, the
hardenable fluidic sealing material 1380 comprises blended cements designed
specifically for the well section being drilled and available from Halliburton
Energy Services in order to optimally provide support for the tubular member
1310 during displacement of the material 1380 in the annular region 1390. The
optimum blend of the cement is preferably determined using conventional
empirical methods.
The annular region 1390 preferably is filled with the material 1380 in
sufficient quantities to ensure that, upon radial expansion of the tubular
member 1310, the annular region 1390 of the new section 1230 of the wellbore
1200 will be filled with material 1380.
As illustrated in Fig. lld, once the annular region 1390 has been
adequately filled with material 1380, a wiper dart 1395, or other similar
device,
is introduced into the fluid passage 1320. The wiper dart 1395 is preferably
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pumped through the fluid passage 1320 by a non hardenable fluidic material
1381. The wiper dart 1395 then preferably engages the wiper plug 1350.
As illustrated in Fig. lle, in a preferred embodiment, engagement of the
wiper dart 1395 with the wiper plug 1350 causes the wiper plug 1350 to
decouple from the mandrel 1305. The wiper dart 1395 and wiper plug 1350
then preferably will lodge in the fluid passage 1330, thereby blocking fluid
flow
through the fluid passage 1330, and fluidicly isolating the interior region
1370
of the tubular member 1310 from the annular region 1390. In a preferred
embodiment, the non hardenable fluidic material 1381 is then pumped into the
interior region 1370 causing the interior region 1370 to pressurize. Once the
interior region 1370 becomes sufficiently pressurized, the tubular member 1310
is extruded off of the expandable mandrel 1305. During the extrusion process,
the expandable mandrel 1305 is raised out of the expanded portion of the
tubular member 1310 by the support member 1345.
The wiper dart 1395 is preferably placed into the fluid passage 1320 by
introducing the wiper dart 1395 into the fluid passage 1320 at a surface
location
in a conventional manner. The wiper dart 1395 may comprise any number of
conventional commercially available devices from plugging a fluid passage such
as, for example, Multiple Stage Cementer latch-down plugs, Omega latch-down
plugs or three wiper latch-down plug/dart modified in accordance with the
teachings of the present disclosure. In a preferred embodiment, the wiper dart
1395 comprises a three wiper latch-down plug modified to latch and seal in the
Multiple Stage Cementer latch down plug 1350. The three wiper latch-down
plug is available from Halliburton Energy Services in Dallas, TX.
After blocking the fluid passage 1330 using the wiper plug 1330 and
wiper dart 1395, the non hardenable fluidic material 1381 may be pumped into
the interior region 1370 at pressures and flow rates ranging, for example,
from
approximately 0 to 5000 psi and 0 to 1,500 gallons/min in order to optimally
extrude the tubular member 1310 off of the mandrel 1305. In this manner, the
amount of hardenable fluidic material within the interior of the tubular
member 1310 is minimized.
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In a preferred embodiment, after blocking the fluid passage 1330, the
non hardenable fluidic material 1381 is preferably pumped into the interior
region 1370 at pressures and flow rates ranging from approximately 500 to
9,000 psi and 40 to 3,000 gallons/min in order to optimally provide operating
pressures to maintain the expansion process at rates sufficient to permit
adjustments to be made in operating parameters during the extrusion process.
For typical tubular members 1310, the extrusion of the tubular member
1310 off of the expandable mandrel 1305 will begin when the pressure of the
interior region 1370 reaches, for example, approximately 500 to 9,000 psi. In
a
preferred embodiment, the extrusion of the tubular member 1310 off of the
expandable mandrel 1305 is a function of the tubular member diameter, wall
thickness of the tubular member, geometry of the mandrel, the type of
lubricant, the composition of the shoe and tubular member, and the yield
strength of the tubular member. The optimum flow rate and operating
pressures are preferably determined using conventional empirical methods.
During the extrusion process, the expandable mandrel 1305 may be
raised out of the expanded portion of the tubular member 1310 at rates
ranging,
for example, from about 0 to 5 ft/sec. In a preferred embodiment, during the
extrusion process, the expandable mandrel 1305 may be raised out of the
expanded portion of the tubular member 1310 at rates ranging from about 0 to
2 ft/sec in order to optimally provide an efficient process, optimally permit
operator adjustment of operation parameters, and ensure optimal completion of
the extrusion process before curing of the material 1380.
When the upper end portion 1355 of the tubular member 1310 is
extruded off of the expandable mandrel 1305, the outer surface of the upper
end
portion 1355 of the tubular member 1310 will preferably contact the interior
surface of the lower end portion of the casing 1215 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 a preferred embodiment, the
contact pressure of the overlapping joint ranges from approximately 400 to
10,000 psi in order to optimally provide contact pressure sufficient to ensure
annular sealing and provide enough resistance to withstand typical tensile and
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compressive loads. In a particularly preferred embodiment, the sealing
members 1340 will ensure an adequate fluidic and gaseous seal in the
overlapping joint.
In a preferred embodiment, the operating pressure and flow rate of the
non hardenable fluidic material 1381 is controllably ramped down when the
expandable mandrel 1305 reaches the upper end portion 1355 of the tubular
member 1310. In this manner, the sudden release of pressure caused by the
complete extrusion of the tubular member 1310 off of the expandable mandrel
1305 can be minimized. In a preferred 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 mandrel 1305 has completed
approximately all but about 5 feet of the extrusion process.
Alternatively, or in combination, a shock absorber is provided in the
support member 1345 in order to absorb the shock caused by the sudden release
of pressure.
Alternatively, or in combination, a mandrel catching structure is
provided in the upper end portion 1355 of the tubular member 1310 in order to
catch or at least decelerate the mandrel 1305.
Once the extrusion process is completed, the expandable mandrel 1305 is
removed from the wellbore 1200. In a preferred embodiment, either before or
after the removal of the expandable mandrel 1305, the integrity of the fluidic
seal of the overlapping joint between the upper portion 1355 of the tubular
member 1310 and the lower portion of the casing 1215 is tested using
conventional methods. If the fluidic seal of the overlapping joint between the
upper portion 1355 of the tubular member 1310 and the lower portion of the
casing 1215 is satisfactory, then the uncured portion of the material 1380
within the expanded tubular member 1310 is then removed in a conventional
manner. The material 1380 within the annular region 1390 is then allowed to
cure.
As illustrated in Fig. 11f, preferably any remaining cured material 1380
within the interior of the expanded tubular member 1310 is then removed in a
conventional manner using a conventional drill string. The resulting new
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section of casing 1400 includes the expanded tubular member 1310 and an
outer annular layer 1405 of cured materia1305. The bottom portion of the
apparatus 1300 comprising the shoe 1315 may then be removed by drilling out
the shoe 1315 using conventional drilling methods.
Referring now to Figs. 12 and 13, a preferred embodiment of a wellhead
system 1500, formed using one or more of the embodiments of the apparatus
and processes described above with reference to Figs. 1-llf, will be
described.
The wellhead system 1500 preferably includes a conventional Christmas
tree/drilling spool assembly 1505, a thick wall casing 1510, an annular body
of
cement 1515, an outer casing 1520, an annular body of cement 1525, an
intermediate casing 1530, and an inner casing 1535.
The Christmas tree/drilling spool assembly 1505 may comprise any
number of conventional Christmas tree/drilling spool assemblies such as, for
example, the SS-15 Subsea Wellhead System, Spool Tree Subsea Production
System or the Compact Wellhead System available from suppliers such as Dril-
Quip, Cameron or Breda, modified in accordance with the teachings of the
present disclosure. The drilling spool assembly 1505 is preferably operably
coupled to the thick wall casing 1510 and/or the outer casing 1520. The
assembly 1505 may be coupled to the thick wall casing 1510 and/or outer casing
1520, for example, by welding, a threaded connection or made from single
stock.
In a preferred embodiment, the assembly 1505 is coupled to the thick wall
casing 1510 and/or outer casing 1520 by welding.
The thick wall casing 1510 is positioned in the upper end of a wellbore
1540. In a preferred embodiment, at least a portion of the thick wall casing
1510 extends above the surface 1545 in order to optimally provide easy access
and attachment to the Christmas tree/drilling spool assembly 1505. The thick
wall casing 1510 is preferably coupled to the Christmas tree/drilling spool
assembly 1505, the annular body of cement 1515, and the outer casing 1520.
The thick wall casing 1510 may comprise any number of conventional
commercially available high strength wellbore casings such as, for example,
Oilfield Country Tubular Goods, titanium tubing or stainless steel tubing. In
a
preferred embodiment, the thick wall casing 1510 comprises Oilfield Country
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Tubular Goods available from various foreign and domestic steel mills. In a
preferred embodiment, the thick wall casing 1510 has a yield strength of about
40,000 to 135,000 psi in order to optimally provide maximum burst, collapse,
and tensile strengths. In a preferred embodiment, the thick wall casing 1510
has a failure strength in excess of about 5,000 to 20,000 psi in order to
optimally provide maximum operating capacity and resistance to degradation of
capacity after being drilled through for an extended time period.
The annular body of cement 1515 provides support for the thick wall
casing 1510. The annular body of cement 1515 may be provided using any
number of conventional processes for forming an annular body of cement in a
wellbore. The annular body of cement 1515 may comprise any number of
conventional cement mixtures.
The outer casing 1520 is coupled to the thick wall casing 1510. The outer
casing 1520 may be fabricated from any number of conventional commercially
available tubular members modified in accordance with the teachings of the
present disclosure. In a preferred embodiment, the outer casing 1520 comprises
any one of the expandable tubular members described above with reference to
Figs. 1-11f.
In a preferred embodiment, the outer casing 1520 is coupled to the thick
wall casing 1510 by expanding the outer casing 1520 into contact with at least
a
portion of the interior surface of the thick wall casing 1510 using any one of
the
embodiments of the processes and apparatus described above with reference to
Figs. 1-11f. In an alternative embodiment, substantially all of the overlap of
the
outer casing 1520 with the thick wall casing 1510 contacts with the interior
surface of the thick wall casing 1510.
The contact pressure of the interface between the outer casing 1520 and
the thick wall casing 1510 may range, for example, from about 500 to 10,000
psi. In a preferred embodiment, the contact pressure between the outer casing
1520 and the thick wall casing 1510 ranges from about 500 to 10,000 psi in
order to optimally activate the pressure activated sealing members and to
ensure that the overlapping joint will optimally withstand typical extremes of
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tensile and compressive loads that are experienced during drilling and
production operations.
As illustrated in Fig. 13, in a particularly preferred embodiment, the
upper end of the outer casing 1520 includes one or more sealing members 1550
that provide a gaseous and fluidic seal between the expanded outer casing 1520
and the interior wall of the thick wall casing 1510. The sealing members 1550
may comprise any number of conventional commercially available seals such as,
for example, lead, plastic, rubber, Teflon or epoxy, modified in accordance
with
the teachings of the present disclosure. In a preferred embodiment, the
sealing
members 1550 comprise seals molded from StrataLock epoxy available from
Halliburton Energy Services in order to optimally provide an hydraulic seal
and
a load bearing interference fit between the tubular members. In a preferred
embodiment, the contact pressure of the interface between the thick wall
casing
1510 and the outer casing 1520 ranges from about 500 to 10,000 psi in order to
optimally activate the sealing members 1550 and also optimally ensure that the
joint will withstand the typical operating extremes of tensile and compressive
loads during drilling and production operations.
In an alternative preferred embodiment, the outer casing 1520 and the
thick walled casing 1510 are combined in one unitary member.
The annular body of cement 1525 provides support for the outer casing
1520. In a preferred embodiment, the annular body of cement 1525 is provided
using any one of the embodiments of the apparatus and processes described
above with reference to Figs. 1-llf.
The intermediate casing 1530 may be coupled to the outer casing 1520 or
the thick wall casing 1510. In a preferred embodiment, the intermediate casing
1530 is coupled to the thick wall casing 1510. The intermediate casing 1530
may be fabricated from any number of conventional commercially available
tubular members modified in accordance with the teachings of the present
disclosure. In a preferred embodiment, the intermediate casing 1530 comprises
any one of the expandable tubular members described above with reference to
Figs. 1-l lf.
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In a preferred embodiment, the intermediate casing 1530 is coupled to
the thick wall casing 1510 by expanding at least a portion of the intermediate
casing 1530 into contact with the interior surface of the thick wall casing
1510
using any one of the processes and apparatus described above with reference to
Figs. 1-llf. In an alternative preferred embodiment, the entire length of the
overlap of the intermediate casing 1530 with the thick wall casing 1510
contacts
the inner surface of the thick wall casing 1510. The contact pressure of the
interface between the intermediate casing 1530 and the thick wall casing 1510
may range, for example from about 500 to 10,000 psi. In a preferred
embodiment, the contact pressure between the intermediate casing 1530 and
the thick wall casing 1510 ranges from about 500 to 10,000 psi in order to
optimally activate the pressure activated sealing members and to optimally
ensure that the joint will withstand typical operating extremes of tensile and
compressive loads experienced during drilling and production operations.
As illustrated in Fig. 13, in a particularly preferred embodiment, the
upper end of the intermediate casing 1530 includes one or more sealing
members 1560 that provide a gaseous and fluidic seal between the expanded
end of the intermediate casing 1530 and the interior wall of the thick wall
casing 1510. The sealing members 1560 may comprise any number of
conventional commercially available seals such as, for example, plastic, lead,
rubber, Teflon or epoxy, modified in accordance with the teachings of the
present disclosure. In a preferred embodiment, the sealing members 1560
comprise seals molded from StrataLock epoxy available from Halliburton
Energy Services in order to optimally provide a hydraulic seal and a load
bearing interference fit between the tubular members.
In a preferred embodiment, the contact pressure of the interface between
the expanded end of the intermediate casing 1530 and the thick wall casing
1510 ranges from about 500 to 10,000 psi in order to optimally activate the
sealing members 1560 and also optimally ensure that the joint will withstand
typical operating extremes of tensile and compressive loads that are
experienced
during drilling and production operations.
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The inner casing 1535 may be coupled to the outer casing 1520 or the
thick wall casing 1510. In a preferred embodiment, the inner casing 1535 is
coupled to the thick wall casing 1510. The inner casing 1535 may be fabricated
from any number of conventional commercially available tubular members
modified in accordance with the teachings of the present disclosure. In a
preferred embodiment, the inner casing 1535 comprises any one of the
expandable tubular members described above with reference to Figs. 1-11f.
In a preferred embodiment, the inner casing 1535 is coupled to the outer
casing 1520 by expanding at least a portion of the inner casing 1535 into
contact with the interior surface of the thick wall casing 1510 using any one
of
the processes and apparatus described above with reference to Figs. 1-llf. In
an alternative preferred embodiment, the entire length of the overlap of the
inner casing 1535 with the thick wall casing 1510 and intermediate casing 1530
contacts the inner surfaces of the thick wall casing 1510 and intermediate
casing 1530. The contact pressure of the interface between the inner casing
1535 and the thick wall casing 1510 may range, for example from about 500 to
10,000 psi. In a preferred embodiment, the contact pressure between the inner
casing 1535 and the thick wall casing 1510 ranges from about 500 to 10,000 psi
in order to optimally activate the pressure activated sealing members and to
ensure that the joint will withstand typical extremes of tensile and
compressive
loads that are commonly experienced during drilling and production operations.
As illustrated in Fig. 13, in a particularly preferred embodiment, the
upper end of the inner casing 1535 includes one or more sealing members 1570
that provide a gaseous and fluidic seal between the expanded end of the inner
casing 1535 and the interior wall of the thick wall casing 1510. The sealing
members 1570 may comprise any number of conventional commercially
available seals such as, for example, lead, plastic, rubber, Teflon or epoxy,
modified in accordance with the teachings of the present disclosure. In a
preferred embodiment, the sealing members 1570 comprise seals molded from
StrataLock epoxy available from Halliburton Energy Services in order to
optimally provide an hydraulic seal and a load bearing interference fit. In a
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preferred embodiment, the contact pressure of the interface between the
expanded end of the inner casing 1535 and the thick wall casing 1510 ranges
from about 500 to 10,000 psi in order to optimally activate the sealing
members
1570 and also to optimally ensure that the joint will withstand typical
operating
extremes of tensile and compressive loads that are experienced during drilling
and production operations.
In an alternative embodiment, the inner casings, 1520, 1530 and 1535,
may be coupled to a previously positioned tubular member that is in turn
coupled to the outer casing 1510. More generally, the present preferred
embodiments may be used to form a concentric arrangement of tubular
members.
A method of creating a casing in a borehole located in a subterranean
formation has been described that includes installing a tubular liner and a
mandrel in the borehole. A body of fluidic material is then injected into the
borehole. The tubular liner is then radially expanded by extruding the liner
off
of the mandrel. The injecting preferably includes injecting a hardenable
fluidic
sealing material into an annular region located between the borehole and the
exterior of the tubular liner; and a non hardenable fluidic material into an
interior region of the tubular liner below the mandrel. The method preferably
includes fluidicly isolating the annular region from the interior region
before
injecting the second quantity of the non hardenable sealing material into the
interior region. The injecting the hardenable fluidic sealing material is
preferably provided at operating pressures and flow rates ranging from about 0
to 5000 psi and 0 to 1,500 gallons/min. The injecting of the non hardenable
fluidic material is preferably provided at operating pressures and flow rates
ranging from about 500 to 9000 psi and 40 to 3,000 gallons/min. The injecting
of the non hardenable fluidic material is preferably provided at reduced
operating pressures and flow rates during an end portion of the extruding. The
non hardenable fluidic material is preferably injected below the mandrel. The
method preferably includes pressurizing a region of the tubular liner below
the
mandrel. The region of the tubular liner below the mandrel is preferably
pressurized to pressures ranging from about 500 to 9,000 psi. The method
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preferably includes fluidicly isolating an interior region of the tubular
liner
from an exterior region of the tubular liner. The method further preferably
includes curing the hardenable sealing material, and removing at least a
portion
of the cured sealing material located within the tubular liner. The method
further preferably includes overlapping the tubular liner with an existing
wellbore casing. The method further preferably includes sealing the overlap
between the tubular liner and the existing wellbore casing. The method further
preferably includes supporting the extruded tubular liner using the overlap
with the existing welibore casing. The method further preferably includes
testing the integrity of the seal in the overlap between the tubular liner and
the
existing wellbore casing. The method further preferably includes removing at
least a portion of the hardenable fluidic sealing material within the tubular
liner before curing. The method further preferably includes lubricating the
surface of the mandrel. The method further preferably includes absorbing
shock. The method further preferably includes catching the mandrel upon the
completion of the extruding.
An apparatus for creating a casing in a borehole located in a
subterranean formation has been described that includes a support member, a
mandrel, a tubular member, and a shoe. The support member includes a first
fluid passage. The mandrel is coupled to the support member and includes a
second fluid passage. The tubular member is coupled to the mandrel. The shoe
is coupled to the tubular liner and includes a third fluid passage. The first,
second and third fluid passages are operably coupled. The support member
preferably further includes a pressure relief passage, and a flow control
valve
coupled to the first fluid passage and the pressure relief passage. The
support
member further preferably includes a shock absorber. The support member
preferably includes one or more sealing members adapted to prevent foreign
material from entering an interior region of the tubular member. The mandrel
is preferably expandable. The tubular member is preferably fabricated from
materials selected from the group consisting of Oilfield Country Tubular
Goods,
13 chromium steel tubing/casing, and plastic casing. The tubular member
preferably has inner and outer diameters ranging from about 3 to 15.5 inches
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and 3.5 to 16 inches, respectively. The tubular member preferably has a
plastic
yield point ranging from about 40,000 to 135,000 psi. The tubular member
preferably includes one or more sealing members at an end portion. The
tubular member preferably includes one or more pressure relief holes at an end
portion. The tubular member preferably includes a catching member at an end
portion for slowing down the mandrel. The shoe preferably includes an inlet
port coupled to the third fluid passage, the inlet port adapted to receive a
plug
for blocking the inlet port. The shoe preferably is drillable.
A method of joining a second tubular member to a first tubular member,
the first tubular member having an inner diameter greater than an outer
diameter of the second tubular member, has been described that includes
positioning a mandrel within an interior region of the second tubular member,
positioning the first and second tubular members in an overlapping
relationship, pressurizing a portion of the interior region of the second
tubular
member; and extruding the second tubular member off of the mandrel into
engagement with the first tubular member. The pressurizing of the portion of
the interior region of the second tubular member is preferably provided at
operating pressures ranging from about 500 to 9,000 psi. The pressurizing of
the portion of the interior region of the second tubular member is preferably
provided at reduced operating pressures during a latter portion of the
extruding. The method further preferably includes sealing the overlap between
the first and second tubular members. The method further preferably includes
supporting the extruded first tubular member using the overlap with the second
tubular member. The method further preferably includes lubricating the
surface of the mandrel. The method further preferably includes absorbing
shock.
A liner for use in creating a new section of wellbore casing in a
subterranean formation adjacent to an already existing section of wellbore
casing has been described that includes an annular member. The annular
member includes one or more sealing members at an end portion of the annular
member, and one or more pressure relief passages at an end portion of the
annular member.
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A wellbore casing has been described that includes a tubular liner and an
annular body of a cured fluidic sealing material. The tubular liner is formed
by
the process of extruding the tubular liner off of a mandrel. The tubular liner
is
preferably formed by the process of placing the tubular liner and mandrel
within the wellbore, and pressurizing an interior portion of the tubular
liner.
The annular body of the cured fluidic sealing material is preferably formed by
the process of injecting a body of hardenable fluidic sealing material into an
annular region external of the tubular liner. During the pressurizing, the
interior portion of the tubular liner is preferably fluidicly isolated from an
exterior portion of the tubular liner. The interior portion of the tubular
liner is
preferably pressurized to pressures ranging from about 500 to 9,000 psi. The
tubular liner preferably overlaps with an existing wellbore casing. The
wellbore
casing preferably further includes a seal positioned in the overlap between
the
tubular liner and the existing wellbore casing. Tubular liner is preferably
supported the overlap with the existing welibore casing.
A method of repairing an existing section of a wellbore casing within a
borehole has been described that includes installing a tubular liner and a
mandrel within the wellbore casing, injecting a body of a fluidic material
into
the borehole, pressurizing a portion of an interior region of the tubular
liner,
and radially expanding the liner in the borehole by extruding the liner off of
the
mandrel. In a preferred embodiment, the fluidic material is selected from the
group consisting of slag mix, cement, drilling mud, and epoxy. In a preferred
embodiment, the method further includes fluidicly isolating an interior region
of the tubular liner from an exterior region of the tubular liner. In a
preferred
embodiment, the injecting of the body of fluidic material is provided at
operating pressures and flow rates ranging from about 500 to 9,000 psi and 40
to 3,000 gallons/min. In a preferred embodiment, the injecting of the body of
fluidic material is provided at reduced operating pressures and flow rates
during an end portion of the extruding. In a preferred embodiment, the fluidic
material is injected below the mandrel. In a preferred embodiment, a region of
the tubular liner below the mandrel is pressurized. In a preferred embodiment,
the region of the tubular liner below the mandrel is pressurized to pressures
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ranging from about 500 to 9,000 psi. In a preferred embodiment, the method
further includes overlapping the tubular liner with the existing wellbore
casing.
In a preferred embodiment, the method further includes sealing the interface
between the tubular liner and the existing wellbore casing. In a preferred
embodiment, the method further includes supporting the extruded tubular liner
using the existing wellbore casing. In a preferred embodiment, the method
further includes testing the integrity of the seal in the interface between
the
tubular liner and the existing wellbore casing. In a preferred embodiment,
method further includes lubricating the surface of the mandrel. In a preferred
embodiment, the method further includes absorbing shock. In a preferred
embodiment, the method further includes catching the mandrel upon the
completion of the extruding. In a preferred embodiment, the method further
includes expanding the mandrel in a radial direction.
A tie-back liner for lining an existing wellbore casing has been described
that includes a tubular liner and an annular body of a cured fluidic sealing
material. The tubular liner is formed by the process of extruding the tubular
liner off of a mandrel. The annular body of a cured fluidic sealing material
is
coupled to the tubular liner. In a preferred embodiment, the tubular liner is
formed by the process of placing the tubular liner and mandrel within the
wellbore, and pressurizing an interior portion of the tubular liner. In a
preferred embodiment, during the pressurizing, the interior portion of the
tubular liner is fluidicly isolated from an exterior portion of the tubular
liner.
In a preferred embodiment, the interior portion of the tubular liner is
pressurized at pressures ranging from about 500 to 9,000 psi. In a preferred
embodiment, the annular body of a cured fluidic sealing material is formed by
the process of injecting a body of hardenable fluidic sealing material into an
annular region between the existing wellbore casing and the tubular liner. In
a
preferred embodiment, the tubular liner overlaps with another existing
wellbore casing. In a preferred embodiment, the tie-back liner further
includes
a seal positioned in the overlap between the tubular liner and the other
existing
wellbore casing. In a preferred embodiment, tubular liner is supported by the
overlap with the other existing wellbore casing.
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An apparatus for expanding a tubular member has been described that
includes a support member, a mandrel, a tubular member, and a shoe. The
support member includes a first fluid passage. The mandrel is coupled to the
support member. The mandrel includes a second fluid passage operably coupled
to the first fluid passage, an interior portion, and an exterior portion. The
interior portion of the mandrel is drillable. The tubular member is coupled to
the mandrel. The shoe is coupled to the tubular member. The shoe includes a
third fluid passage operably coupled to the second fluid passage, an interior
portion, and an exterior portion. The interior portion of the shoe is
drillable.
Preferably, the interior portion of the mandrel includes a tubular member and
a
load bearing member. Preferably, the load bearing member comprises a
drillable body. Preferably, the interior portion of the shoe includes a
tubular
member, and a load bearing member. Preferably, the load bearing member
comprises a drillable body. Preferably, the exterior portion of the mandrel
comprises an expansion cone. Preferably, the expansion cone is fabricated from
materials selected from the group consisting of tool steel, titanium, and
ceramic. Preferably, the expansion cone has a surface hardness ranging from
about 58 to 62 Rockwell C. Preferably at least a portion of the apparatus is
drillable.
An wellhead has also been described that includes an outer casing and a
plurality of substantially concentric and overlapping inner casings coupled to
the outer casing. Each inner casing is supported by contact pressure between
an outer surface of the inner casing and an inner surface of the outer casing.
In
a preferred embodiment, the outer casing has a yield strength ranging from
about 40,000 to 135,000 psi. In a preferred embodiment, the outer casing has a
burst strength ranging from about 5,000 to 20,000 psi. In a preferred
embodiment, the contact pressure between the inner casings and the outer
casing ranges from about 500 to 10,000 psi. In a preferred embodiment, one or
more of the inner casings include one or more sealing members that contact
with an inner surface of the outer casing. In a preferred embodiment, the
sealing members are selected from the group consisting of lead, rubber,
Teflon,
epoxy, and plastic. In a preferred embodiment, a Christmas tree is coupled to
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the outer casing. In a preferred embodiment, a drilling spool is coupled to
the
outer casing. In a preferred embodiment, at least one of the inner casings is
a
production casing.
A wellhead has also been described that includes an outer casing at least
partially positioned within a wellbore and a plurality of substantially
concentric
inner casings coupled to the interior surface of the outer casing by the
process
of expanding one or more of the inner casings into contact with at least a
portion of the interior surface of the outer casing. In a preferred
embodiment,
the inner casings are expanded by extruding the inner casings off of a
mandrel.
In a preferred embodiment, the inner casings are expanded by the process of
placing the inner casing and a mandrel within the wellbore; and pressurizing
an
interior portion of the inner casing. In a preferred embodiment, during the
pressurizing, the interior portion of the inner casing is fluidicly isolated
from an
exterior portion of the inner casing. In a preferred embodiment, the interior
portion of the inner casing is pressurized at pressures ranging from about 500
to 9,000 psi. In a preferred embodiment, one or more seals are positioned in
the
interface between the inner casings and the outer casing. In a preferred
embodiment, the inner casings are supported by their contact with the outer
casing.
A method of forming a wellhead has also been described that includes
drilling a wellbore. An outer casing is positioned at least partially within
an
upper portion of the wellbore. A first tubular member is positioned within the
outer casing. At least a portion of the first tubular member is expanded into
contact with an interior surface of the outer casing. A second tubular member
is positioned within the outer casing and the first tubular member. At least a
portion of the second tubular member is expanded into contact with an interior
portion of the outer casing. In a preferred embodiment, at least a portion of
the
interior of the first tubular member is pressurized. In a preferred
embodiment, at least a portion of the interior of the second tubular member is
pressurized. In a preferred embodiment, at least a portion of the interiors of
the first and second tubular members are pressurized. In a preferred
embodiment, the pressurizing of the portion of the interior region of the
first
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tubular member is provided at operating pressures ranging from about 500 to
9,000 psi. In a preferred embodiment, the pressurizing of the portion of the
interior region of the second tubular member is provided at operating
pressures
ranging from about 500 to 9,000 psi. In a preferred embodiment, the
pressurizing of the portion of the interior region of the first and second
tubular
members is provided at operating pressures ranging from about 500 to 9,000
psi. In a preferred embodiment, the pressurizing of the portion of the
interior
region of the first tubular member is provided at reduced operating pressures
during a latter portion of the expansion. In a preferred embodiment, the
pressurizing of the portion of the interior region of the second tubular
member
is provided at reduced operating pressures during a latter portion of the
expansion. In a preferred embodiment, the pressurizing of the portion of the
interior region of the first and second tubular members is provided at reduced
operating pressures during a latter portion of the expansions. In a preferred
embodiment, the contact between the first tubular member and the outer
casing is sealed. In a preferred embodiment, the contact between the second
tubular member and the outer casing is sealed. In a preferred embodiment, the
contact between the first and second tubular members and the outer casing is
sealed. In a preferred embodiment, the expanded first tubular member is
supported using the contact with the outer casing. In a preferred embodiment,
the expanded second tubular member is supported using the contact with the
outer casing. In a preferred embodiment, the expanded first and second tubular
members are supported using their contacts with the outer casing. In a
preferred embodiment, the first and second tubular members are extruded off
of a mandrel. In a preferred embodiment, the surface of the mandrel is
lubricated. In a preferred embodiment, shock is absorbed. In a preferred
embodiment, the mandrel is expanded in a radial direction. In a preferred
embodiment, the first and second tubular members are positioned in an
overlapping relationship. In a preferred embodiment, an interior region of the
first tubular member is fluidicly isolated from an exterior region of the
first
tubular member. In a preferred embodiment, an interior region of the second
tubular member is fluidicly isolated from an exterior region of the second
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tubular member. In a preferred embodiment, the interior region of the first
tubular member is fluidicly isolated from the region exterior to the first
tubular
member by injecting one or more plugs into the interior of the first tubular
member. In a preferred embodiment, the interior region of the second tubular
member is fluidicly isolated from the region exterior to the second tubular
member by injecting one or more plugs into the interior of the second tubular
member. In a preferred embodiment, the pressurizing of the portion of the
interior region of the first tubular member is provided by injecting a fluidic
material at operating pressures and flow rates ranging from about 500 to 9,000
psi and 40 to 3,000 gallons/minute. In a preferred embodiment, the
pressurizing of the portion of the interior region of the second tubular
member
is provided by injecting a fluidic material at operating pressures and flow
rates
ranging from about 500 to 9,000 psi and 40 to 3,000 gallons/minute. In a
preferred embodiment, fluidic material is injected beyond the mandrel. In a
preferred embodiment, a region of the tubular members beyond the mandrel is
pressurized. In a preferred embodiment, the region of the tubular members
beyond the mandrel is pressurized to pressures ranging from about 500 to 9,000
psi. In a preferred embodiment, the first tubular member comprises a
production casing. In a preferred embodiment, the contact between the first
tubular member and the outer casing is sealed. In a preferred embodiment, the
contact between the second tubular member and the outer casing is sealed. In a
preferred embodiment, the expanded first tubular member is supported using
the outer casing. In a preferred embodiment, the expanded second tubular
member is supported using the outer casing. In a preferred embodiment, the
integrity of the seal in the contact between the first tubular member and the
outer casing is tested. In a preferred embodiment, the integrity of the seal
in
the contact between the second tubular member and the outer casing is tested.
In a preferred embodiment, the mandrel is caught upon the completion of the
extruding. In a preferred embodiment, the mandrel is drilled out. In a
preferred embodiment, the mandrel is supported with coiled tubing. In a
preferred embodiment, the mandrel is coupled to a drillable shoe.
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An apparatus has also been described that includes an outer tubular
member, and a plurality of substantially concentric and overlapping inner
tubular members coupled to the outer tubular member. Each inner tubular
member is supported by contact pressure between an outer surface of the inner
casing and an inner surface of the outer inner tubular member. In a preferred
embodiment, the outer tubular member has a yield strength ranging from about
40,000 to 135,000 psi. In a preferred embodiment, the outer tubular member
has a burst strength ranging from about 5,000 to 20,000 psi. In a preferred
embodiment, the contact pressure between the inner tubular members and the
outer tubular member ranges from about 500 to 10,000 psi. In a preferred
embodiment, one or more of the inner tubular members include one or more
sealing members that contact with an inner surface of the outer tubular
member. In a preferred embodiment, the sealing members are selected from
the group consisting of rubber, lead, plastic, and epoxy.
An apparatus has also been described that includes an outer tubular
member, and a plurality of substantially concentric inner tubular members
coupled to the interior surface of the outer tubular member by the process of
expanding one or more of the inner tubular members into contact with at least
a portion of the interior surface of the outer tubular member. In a preferred
embodiment, the inner tubular members are expanded by extruding the inner
tubular members off of a mandrel. In a preferred embodiment, the inner
tubular members are expanded by the process of: placing the inner tubular
members and a mandrel within the outer tubular member; and pressurizing an
interior portion of the inner casing. In a preferred embodiment, during the
pressurizing, the interior portion of the inner tubular member is fluidicly
isolated from an exterior portion of the inner tubular member. In a preferred
embodiment, the interior portion of the inner tubular member is pressurized at
pressures ranging from about 500 to 9,000 psi. In a preferred embodiment, the
apparatus further includes one or more seals positioned in the interface
between the inner tubular members and the outer tubular member. In a
preferred embodiment, the inner tubular members are supported by their
contact with the outer tubular member.
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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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