Note: Descriptions are shown in the official language in which they were submitted.
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MONO-DIAMETER WELLBORE CASING
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, valuing, and a Christmas tree. Typically the wellhead further includes
a
concentric arrangement 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.
According to another aspect of the present invention, a wellbore casing is
provided that includes a first tubular member, and a second tubular member
coupled to the first tubular member in an overlapping relationship. The inner
diameter of the first tubular member is substantially equal to the inner
diameter of the second tubular member.
According to another aspect of the present invention, a wellbore casing is
provided that includes a tubular member including at least one thin wall
section
and a thick wall section, and a compressible annular member coupled to each
thin wall section.
According to another aspect of the present invention, a method of
creating a casing in a borehole located in a subterranean formation is
provided
that includes supporting a tubular liner and a mandrel in the borehole using a
support member. A fluidic material is injected into the borehole. An interior
region of the mandrel is pressurized. A portion of the mandrel is displaced
relative to the support member. The tubular liner is expanded.
According to another aspect of the present invention, a wellbore casing is
provided that includes a first tubular member having a first inside diameter,
and a second tubular member having a second inside diameter substantially
equal to the first inside diameter coupled to the first tubular member in an
overlapping relationship. The first and second tubular members are coupled by
the process of deforming a portion of the second tubular member into contact
with a portion of the first tubular member
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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
including a fluid passage, a mandrel movably coupled to the support member
including an expansion cone, at least one pressure chamber defined by and
positioned between the support member and mandrel fluidicly coupled to the
first fluid passage, and one or more releasable supports coupled to the
support
member adapted to support the tubular member.
According to another aspect of the present invention, an apparatus is
provided that includes one or more solid tubular members, each solid tubular
member including one or more external seals, one or more slotted tubular
members coupled to the solid tubular members, and a shoe coupled to one of the
slotted tubular members.
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 the interior region of the
mandrel is pressurized. The mandrel is displaced relative to the second
tubular
member. At least a portion of 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, an apparatus is
provided that includes one or more primary solid tubulars, each primary solid
tubular including one or more external annular seals, n slotted tubulars
coupled to the primary solid tubulars, n-1 intermediate solid tubulars coupled
to
and interleaved among the slotted tubulars, each intermediate solid tubular
including one or more external annular seals, and a shoe coupled to one of the
slotted tubulars.
According to another aspect of the present invention, a method of
isolating a first subterranean zone from a second subterranean zone in a
wellbore is provided that includes positioning one or more primary solid
tubulars within the wellbore, the primary solid tubulars traversing the first
subterranean zone. One or more slotted tubulars are also positioned within the
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wellbore, the slotted tubulars traversing the second subterranean zone. The
slotted tubulars and the solid tubulars are fluidicly coupled. The passage of
fluids from the first subterranean zone to the second subterranean zone within
the wellbore external to the solid and slotted tubulars is prevented.
According to another aspect of the present invention, a method of
extracting materials from a producing subterranean zone in a wellbore, at
least
a portion of the wellbore including a casing, is provided that includes
positioning one or more primary solid tubulars within the wellbore. The
primary solid tubulars with the casing are fluidicly coupled. One or more
slotted tubulars are positioned within the wellbore, the slotted tubulars
traversing the producing subterranean zone. The slotted tubulars are fluidicly
coupled with the solid tubulars. The producing subterranean zone is fluidicly
isolated from at least one other subterranean zone within the wellbore. At
least
one of the slotted tubulars is fluidicly isolated from the producing
subterranean
zone.
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 fluidic 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 fluidic 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.
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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.
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. 10b 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. l0e 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. llb 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.
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FIG. 11c 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. lld is a fragmentary cross-sectional view illustrating the
introduction of a wiper dart into the new section of the well borehole.
FIG. lle 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. 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.
FIG. 14a is an illustration of the formation of an embodiment of a mono-
diameter wellbore casing.
FIG. 14b is another illustration of the formation of the mono-diameter
wellbore casing.
FIG. 14c is another illustration of the formation of the mono-diameter
wellbore casing.
FIG. 14d is another illustration of the formation of the mono-diameter
welbore casing.
FIG. 14e is another illustration of the formation of the mono-diameter
welbore casing.
FIG. 14f is another illustration of the formation of the mono-diameter
welbore casing.
FIG. 15 is an illustration of an embodiment of an apparatus for
expanding a tubular member.
FIG. 15a is another illustration of the apparatus of FIG. 15.
FIG. 15b is another illustration of the apparatus of FIG. 15.
FIG. 16 is an illustration of an embodiment of an apparatus for forming
a mono-diameter wellbore casing.
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FIG. 17 is an illustration of an embodiment of an apparatus for
expanding a tubular member.
FIG. 17a is another illustration of the apparatus of FIG. 16.
FIG. 17b is another illustration of the apparatus of FIG. 16.
FIG. 18 is an illustration of an embodiment of an apparatus for forming
a mono-diameter wellbore casing.
FIG. 19 is an illustration of another embodiment of an apparatus for
expanding a tubular member.
FIG. 19a is another illustration of the apparatus of FIG. 17.
FIG. 19b is another illustration of the apparatus of FIG. 17.
FIG. 20 is an illustration of an embodiment of an apparatus for forming
a mono-diameter wellbore casing.
FIG. 21 is an illustration of the isolation of subterranean zones using
expandable tubulars.
1~ 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
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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 andlor 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.
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.
An apparatus and method for forming a mono-diameter well casing is
also provided. The apparatus and method permit the creation of a well casing
in a wellbore having a substantially constant internal diameter. In this
manner, the operation of an oil or gas well is greatly simplified.
An apparatus and method for expanding tubular members is also
provided. The apparatus and method utilize a piston-cylinder configuration in
which a pressurized chamber is used to drive a mandrel to radially expand
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tubular members. In this manner, higher operating pressures can be utilized.
Throughout the radial expansion process, the tubular member is never placed
in direct contact with the operating pressures. In this manner, damage to the
tubular member is prevented while also permitting controlled radial expansion
of the tubular member in a wellbore.
An apparatus and method for forming a mono-diameter wellbore casing
is also.provided. The apparatus and method utilize a piston-cylinder
configuration in which a pressurized chamber is used to drive a mandrel to
radially expand tubular members. In this manner, higher operating pressures
can be utilized. Throughput the radial expansion process, the tubular member
is never placed in direct contact with the operating pressures. In this
manner,
damage to the tubular member is prevented while also permitting controlled
radial expansion of the tubular member in a wellbore.
An apparatus and method for isolating one or more subterranean zones
from one or more other subterranean zones is also provided. The apparatus
and method permits a producing zone to be isolated from a nonproducing zone
using a combination of solid and slotted tubulars. In the production mode, the
teachings of the present disclosure may be used in combination with
conventional, well known, production completion equipment and methods using
a series of packers, solid tubing, perforated tubing, and sliding sleeves,
which
will be inserted into the disclosed apparatus to permit the commingling and/or
isolation of the subterranean zones from each other.
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.
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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
seal 225, 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 mandrel 205 is preferably adapted to controllably
expand in a radial direction. The expandable mandrel 205 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 205 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 mandrel 205.
The tubular member 210 is expanded in the radial direction and extruded off of
the expandable mandrel 205. 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
mandrel 205 when it completes the extrusion of tubular member 210. In a
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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.
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 seal 220 is coupled to and supported by the support
member 250. The lower cup seal 220 prevents foreign materials from entering
the interior region of the tubular member 210 adjacent to the expandable
mandrel 205. The lower cup seal 220 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
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of the present disclosure. In a preferred embodiment, the lower cup seal 220
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.
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
mandrel 205. 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.
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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
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 mandrel 205. 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
wellbore 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
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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
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 mandrel 205 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 Aotisieze (3100). In a preferred embodiment, the lubricant 275
comprises Climax 1500 Aotisieze (3100) available from Climax Lubricants and
Equipment Co. in Houston, TX in order to optimally provide optimum
lubrication to faciliate the expansion process.
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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
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 mandrel 205. The material 305 then passes from the interior region
310 into the fluid passage 240. The material 305 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 material 305 causes the material 305 to fill up at least a
portion
of the annular region 315.
The material 305 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 material 305 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 305 comprises a blended cement prepared
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specifically for the particular well section being drilled from Halliburton
Energ~~
Services in Dallas, TX in order to provide optimal support for tubular member
210 while also maintaining optimum flow characteristics so as to minimize
difficulties during the displacement of cement in the annular region 315. The
optimum blend of the blended cement is preferably determined using
conventional empirical methods.
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 material 305.
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 mandrel 205. During the
extrusion process, the expandable mandrel 205 may be raised out of the
expanded portion of the tubular member 210. In a preferred embodiment,
during the extrusion process, the mandrel 205 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
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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 mandrel 205 stationary, and allowing the tubular member 210
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
materia1306.
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 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
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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
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
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210. In this manner, the sudden release of pressure caused by the complete
extrusion of the tubular member 210 off of the expandable mandrel 205 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 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
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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
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
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mandrel container 710. The expandable mandrel 705 is preferably adapted to
controllably expand in a radial direction. The expandable mandrel 705 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 705 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.
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In a preferred embodiment, the tubular member 715 has a substantiall~~
annular cross-section. In a particularly preferred embodiment, the tubular
member 715 has a substantially circular annular cross-section.
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
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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
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
?05 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 ?15 and an existing wellbore casing, and to optimally faciliate
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the removal of the shoe 720 by drilling it out after completion of the
extrusion
process.
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 seal 730 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
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optimally provide sufficient operating pressures to extrude the tubular member
715 off of the expandable mandrel 705.
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 mandrel 705. 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
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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
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 casing. In a preferred embodiment, the frictional force provided by
the
seals 845 ranges from about 1,000 to 1,000,000 lbf in order to optimally
support
the expanded tubular member 715.
The support member 745 is preferably coupled to the expandable
mandrel 705 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
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tubular modified in accordance with the teachings of the present disclosure.
In
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 mandrel 705 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 Antisieze (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 Drill Setting
Tool
Stinger. 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 drill pipe available from steel mills in the United
States.
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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
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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 mandrel 906 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 preferable
extruded off of the mandrel 906 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
mandrel 906.
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, TP cups
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 mandrel 902 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. 7 5
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 mandrel 946
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 94$. 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 mandrel 906. The
mandrel 906 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 MSC latch-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 material 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 mandrel 906.
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
mandrel 906 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 mandrel 906 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 mandrel 906.
Once the extrusion process is completed, the mandrel 906 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, 10b, lOc, lOd, 10e, lOf, 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.
lla-llf.
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 preferabh>
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 1146
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 1,000,000 lbf 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 Packer, EZ SV Packer or a drillable cement retainer. In a preferred
embodiment, the packer 1155 comprises an EZ Drill Packer available from
Halliburton Energy Services in Dallas, TX. In an alternative embodiment, a
high gel strength pill 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. lOc, 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 Iialliburton 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 ofl' 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. lOf, 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. lOg, 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-11f, 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. 11a, 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. llb, 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 4?
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/~ inches
and 3 1/a 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
nev~~ 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 cf 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 is 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. llf, 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 material 305. 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 apparatus and processes described
above with reference to Figs. 1-11f 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-l lf.
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-llf. 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-l lf. 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-llf.
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.
A,s 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.
Referring now to Figures 14a, 14b, 14c, 14d, 14e and 14f, a preferred
embodiment of a method and apparatus for forming a mono-diameter well
casing within a subterranean formation will now be described.
As illustrated in Fig. 14a, a wellbore 1600 is positioned in a subterranean
formation 1605. A first section of casing 1610 is formed in the wellbore 1600.
The first section of casing 1610 includes an annular outer body of cement 1615
and a tubular section of casing 1620. The first section of casing 1610 may be
formed in the wellbore 1600 using conventional methods and apparatus. In a
preferred embodiment, the first section of casing 1610 is formed using one or
more of the methods and apparatus described above with reference to Figs. 1-13
or below with reference to Figs. 14b-17b.
The annular body of cement 1615 may comprise any number of
conventional commercially available cement, or other load bearing,
compositions. Alternatively, the body of cement 1615 may be omitted or
replaced with an epoxy mixture.
The tubular section of casing 1620 preferably includes an upper end 1625
and a lower end 1630. Preferably, the lower end 1625 of the tubular section of
casing 1620 includes an outer annular recess 1635 extending from the lower
end 1630 of the tubular section of casing 1620. In this manner, the lower end
1625 of the tubular section of casing 1620 includes a thin walled section
1640.
In a preferred embodiment, an annular body 1645 of a compressible material is
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coupled to and at least partially positioned within the outer annular recess
1635. In this manner, the body of compressible material 1645 surrounds at
least a portion of the thin walled section 1640.
The tubular section of casing 1620 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, stainless steel, automotive grade steel, carbon steel,
low
alloy steel, fiberglass or plastics. In a preferred embodiment, the tubular
section of casing 1620 is fabricated from oilfield country tubular goods
available
from various foreign and domestic steel mills. The wall thickness of the thin
walled section 1640 may range from about 0.125 to 1.5 inches. In a preferred
embodiment, the wall thickness of the thin walled section 1640 ranges from
0.25 to 1.0 inches in order to optimally provide burst strength for typical
operational conditions while also minimizing resistance to radial expansion.
The axial length of the thin walled section 1640 may range from about 120 to
2400 inches. In a preferred embodiment, the axial length of the thin walled
section 1640 ranges from about 240 to 480 inches.
The annular body of compressible material 1645 helps to minimize the
radial force required to expand the tubular casing 1620 in the overlap with
the
tubular member 1715, helps to create a fluidic seal in the overlap with the
tubular member 1715, and helps to create an interference fit sufficient to
permit the tubular member 1715 to be supported by the tubular casing 1620.
The annular body of compressible material 1645 may comprise any number of
commercially available compressible materials such as, for example, epoxy,
rubber, Teflon, plastics or lead tubes. In a preferred embodiment, the annular
body of compressible material 1645 comprises StrataLock epoxy available from
Halliburton Energy Services in order to optimally provide an hydraulic seal in
the overlapped joint while also having compliance to thereby minimize the
radial force required to expand the tubular casing. The wall thickness of the
annular body of compressible material 1645 may range from about 0.05 to 0.75
inches. In a preferred embodiment, the wall thickness of the annular body of
compressible material 1645 ranges from about 0.1 to 0.5 inches in order to
optimally provide a large compressible zone, minimize the radial forces
required
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to expand the tubular casing, provide thickness for casing strings to provide
contact with the inner surface of the wellbore upon radial expansion, and
provide an hydraulic seal.
As illustrated in Fig. 14b, in order to extend the wellbore 1600 into the
subterranean formation 1605, a drill string is used in a well known manner to
drill out material from the subterranean formation 1605 to form a new wellbore
section 1650. The diameter of the new section 1650 is preferably equal to or
greater than the inner diameter of the tubular section of casing 1620.
As illustrated in Fig. 14c, a preferred embodiment of an apparatus 1700
for forming a mono-diameter wellbore casing in a subterranean formation is
then positioned in the new section 1650 of the wellbore 1600. The apparatus
1700 preferably includes a support member 1705, an expandable mandrel or pig
1710, a tubular member 1715, a shoe 1720, slips 1725, a fluid passage 1730,
one
or more fluid passages 1735, a fluid passage 1740, a first compressible
annular
body 1745, a second compressible annular body 1750, and a pressure chamber
1755.
The support member 1705 supports the apparatus 1700 within the
wellbore 1600. The support member 1705 is coupled to the mandrel 1710, the
tubular member 1715, the shoe 1720, and the slips 1725. The support member
1075 preferably comprises a substantially hollow tubular member. The fluid
passage 1730 is positioned within the support member 1705. The fluid passages
1735 fluidicly couple the fluid passage 1730 with the pressure chamber 1755.
The fluid passage 1740 fluidicly couples the fluid passage 1730 with the
region
outside of the apparatus 1700.
The support member 1705 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, stainless steel, low alloy steel, carbon steel, 13
chromium
steel, fiberglass, or other high strength materials. In a preferred
embodiment,
the support member 1705 is fabricated from oilfield country tubular goods
available from various foreign and domestic steel mills in order to optimally
provide operational strength and faciliate the use of other standard oil
exploration handling equipment. In a preferred embodiment, at least a portion
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of the support member 1705 comprises coiled tubing or a drill pipe. In a
particularly preferred embodiment, the support member 1705 includes a load
shoulder 1820 for supporting the mandrel 1710 when the pressure chamber
1755 is unpressurized.
The mandrel 1710 is supported by and slidingly coupled to the support
member 1705 and the shoe 1720. The mandrel 1710 preferably includes an
upper portion 1760 and a lower portion 1765. Preferably, the upper portion
1760 of the mandrel 1710 and the support member 1705 together define the
pressure chamber 1755. Preferably, the lower portion 1765 of the mandrel 1710
includes an expansion member 1770 for radially expanding the tubular member
1715.
In a preferred embodiment, the upper portion 1760 of the mandrel 1710
includes a tubular member 1775 having an inner diameter greater than an
outer diameter of the support member 1705. In this manner, an annular
pressure chamber 1755 is defined by and positioned between the tubular
member 1775 and the support member 1705. The top 1780 of the tubular
member 1775 preferably includes a bearing and a seal for sealing and
supporting the top 1780 of the tubular member 1775 against the outer surface
of the support member 1705. The bottom 1785 of the tubular member 1775
preferably includes a bearing and seal for sealing and supporting the bottom
1785 of the tubular member 1775 against the outer surface of the support
member 1705 or shoe 1720. In this manner, the mandrel 1710 moves in an
axial direction upon the pressurization of the pressure chamber 1755.
The lower portion 1765 of the mandrel 1710 preferably includes an
expansion member 1770 for radially expanding the tubular member 1715
during the pressurization of the pressure chamber 1755. In a preferred
embodiment, the expansion member is expandible in the radial direction. In a
preferred embodiment, the inner surface of the lower portion 1765 of the
mandrel 1710 mates with and slides with respect to the outer surface of the
shoe 1720. The outer diameter of the expansion member 1770 may range from
about 90 to 100 % of the inner diameter of the tubular casing 1620. In a
preferred embodiment, the outer diameter of the expansion member 1770
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ranges from about 95 to 99 % of the inner diameter of the tubular casing 1620.
The expansion member 1770 may be fabricated from any number of
conventional commercially available materials such as, for example, machine
tool steel, ceramics, tungsten carbide, titanium or other high strength
alloys. In
a preferred embodiment, the expansion member 1770 is fabricated from D2
machine tool steel in order to optimally provide high strength and abrasion
resistance.
The tubular member 1715 is coupled to and supported by the support
member 1705 and slips 1725. The tubular member 1715 includes an upper
portion 1790 and a lower portion 1795.
The upper portion 1790 of the tubular member 1715 preferably includes
an inner annular recess 1800 that extends from the upper portion 1790 of the
tubular member 1715. In this manner, at least a portion of the upper portion
1790 of the tubular member 1715 includes a thin walled section 1805. The first
compressible annular member 1745 is preferably coupled to and supported by
the outer surface of the upper portion 1790 of the tubular member 1715 in
opposing relation to the thin wall section 1805.
The lower portion 1795 of the tubular member 1715 preferably includes
an outer annular recess 1810 that extends from the lower portion 1790 of the
tubular member 1715. In this manner, at least a portion of the lower portion
1795 of the tubular member 1715 includes a thin walled section 1815. The
second compressible annular member 1750 is coupled to and at least partially
supported within the outer annular recess 1810 of the upper portion 1790 of
the
tubular member 1715 in opposing relation to the thin wall section 1815.
The tubular member 1715 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, stainless steel, low alloy steel, carbon steel,
automotive
grade steel, fiberglass, 13 chrome steel, other high strength material, or
high
strength plastics. In a preferred embodiment, the tubular member 1715 is
fabricated from oilfield country tubular goods available from various foreign
and domestic steel mills in order to optimally provide operational strength.
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The shoe 1720 is supported by and coupled to the support member 1705.
The shoe 1720 preferably comprises a substantially hollow tubular member. In
a preferred embodiment, the wall thickness of the shoe 1720 is greater than
the
wall thickness of the support member 1705 in order to optimally provide
increased radial support to the mandrel 1710. The shoe 1720 may be fabricated
from any number of conventional commercially available materials such as, for
example, oilfield country tubular goods, stainless steel, automotive grade
steel,
low alloy steel, carbon steel, or high strength plastics. In a preferred
embodiment, the shoe 1720 is fabricated from oilfield country tubular goods
available from various foreign and domestic steel mills in order to optimally
provide matching operational strength throughout the apparatus.
The slips 1725 are coupled to and supported by the support member
1705. The slips 1725 removably support the tubular member 1715. In this
manner, during the radial expansion of the tubular member 1715, the slips
1725 help to maintain the tubular member 1715 in a substantially stationary
position by preventing upward movement of the tubular member 1715.
The slips 1725 may comprise any number of conventional commercially
available slips such as, for example, RTTS packer tungsten carbide mechanical
slips, RTTS packer wicker type mechanical slips, or Model 3L retrievable
bridge
plug tungsten carbide upper mechanical slips. In a preferred embodiment, the
slips 1725 comprise RTTS packer tungsten carbide mechanical slips available
from Halliburton Energy Services. In a preferred embodiment, the slips 1725
are adapted to support axial forces ranging from about 0 to 750,000 lbf.
The fluid passage 1730 conveys fluidic materials from a surface location
into the interior of the support member 1705, the pressure chamber 1755, and
the region exterior of the apparatus 1700. The fluid passage 1730 is fludicly
coupled to the pressure chamber 1755 by the fluid passages 1735. The fluid
passage 1730 is fluidicly coupled to the region exterior to the apparatus 1700
by
the fluid passage 1740.
In a preferred embodiment, the fluid passage 1730 is adapted to convey
fluidic materials such as, for example, cement, epoxy, drilling muds, slag
mix,
water or drilling gasses. In a preferred embodiment, the fluid passage 1730 is
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adapted to convey fluidic materials at flow rate and pressures ranging from
about 0 to 3,000 gallons/minute and 0 to 9,000 psi. in order to optimally
provide
flow rates and operational pressures for the radial expansion processes.
The fluid passages 1735 convey fluidic material from the fluid passage
1730 to the pressure chamber 1755. In a preferred embodiment, the fluid
passage 1735 is adapted to convey fluidic materials such as, for example,
cement, epoxy, drilling muds, water or drilling gasses. In a preferred
embodiment, the fluid passage 1735 is adapted to convey fluidic materials at
flow rate and pressures ranging from about 0 to 500 gallons/minute and 0 to
9,000 psi. in order to optimally provide operating pressures and flow rates
for
the various expansion processes.
The fluid passage 1740 conveys fluidic materials from the fluid passage
1730 to the region exterior to the apparatus 1700. In a preferred embodiment,
the fluid passage 1740 is adapted to convey fluidic materials such as, for
example, cement, epoxy, drilling muds, water or drilling gasses. In a
preferred
embodiment, the fluid passage 1740 is adapted to convey fluidic materials at
flow rate and pressures ranging from about 0 to 3,000 gallons/minute and 0 to
9,000 psi. in order to optimally provide operating pressures and flow rates
for
the various radial expansion processes.
In a preferred embodiment, the fluid passage 1740 is adapted to receive a
plug or other similar device for sealing the fluid passage 1740. In this
manner,
the pressure chamber 1755 may be pressurized.
The first compressible annular body 1745 is coupled to and supported by
an exterior surface of the upper portion 1790 of the tubular member 1715. In a
preferred embodiment, the first compressible annular body 1745 is positioned
in opposing relation to the thin walled section 1805 of the tubular member
1715.
The first compressible annular body 1745 helps to minimize the radial
force required to expand the tubular member 1715 in the overlap with the
tubular casing 1620, helps to create a fluidic seal in the overlap with the
tubular
casing 1620, and helps to create an interference fit sufficient to permit the
tubular member 1715 to be supported by the tubular casing 1620. The first
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compressible annular body 1745 may comprise any number of commercially
available compressible materials such as, for example, epoxy, rubber, Teflon,
plastics, or hollow lead tubes. In a preferred embodiment, the first
compressible annular body 1745 comprises StrataLock epoxy available from
Halliburton Energy Services in order to optimally provide an hydraulic seal,
and compressibility to minimize the radial expansion force.
The wall thickness of the first compressible annular body 1745 may
range from about 0.05 to 0.75 inches. In a preferred embodiment, the wall
thickness of the first compressible annular body 1745 ranges from about 0.1 to
0.5 inches in order to optimally (1) provide a large compressible zone, (2)
minimize the required radial expansion force, (3) transfer the radial force to
the
tubular casings. As a result, in a preferred embodiment, overall the outer
diameter of the tubular member 1715 is approximately equal to the overall
inner diameter of the tubular member 1620.
The second compressible annular body 1750 is coupled to and at least
partially supported within the outer annular recess 1810 of the tubular member
1715. In a preferred embodiment, the second compressible annular body 1750
is positioned in opposing relation to the thin walled section 1815 of the
tubular
member 1715.
The second compressible annular body 1750 helps to minimize the radial
force required to expand the tubular member 1715 in the overlap with another
tubular member, helps to create a fluidic seal in the overlap of the tubular
member 1715 with another tubular member, and helps to create an interference
fit sufficient to permit another tubular member to be supported by the tubular
member 1715. The second compressible annular body 1750 may comprise any
number of commercially available compressible materials such as, for example,
epoxy, rubber, Teflon, plastics or hollow lead tubing. In a preferred
embodiment, the first compressible annular body 1750 comprises StrataLock
epoxy available from Halliburton Energy Services in order to optimally provide
an hydraulic seal in the overlapped joint, and compressibility that minimizes
the radial expansion force.
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The wall thickness of the second compressible annular body 1750 may
range from about 0.05 to 0.75 inches. In a preferred embodiment, the wall
thickness of the second compressible annular body 1750 ranges from about 0.1
to 0.5 inches in order to optimally provide a large compressible zone, and
minimize the radial force required to expand the tubular member 1715 during
subsequent radial expansion operations.
In an alternative embodiment, the outside diameter of the second
compressible annular body 1750 is adapted to provide a seal against the
surrounding formation thereby eliminating the need for an outer annular body
of cement.
The pressure chamber 1755 is fludicly coupled to the fluid passage 1730
by the fluid passages 1735. The pressure chamber 1755 is preferably adapted to
receive fluidic materials such as, for example, drilling muds, water or
drilling
gases. In a preferred embodiment, the pressure chamber 1755 is adapted to
receive fluidic materials at flow rate and pressures ranging from about 0 to
500
gallons/minute and 0 to 9,000 psi. in order to optimally provide expansion
pressure. In a preferred embodiment, during pressurization of the pressure
chamber 1755, the operating pressure of the pressure chamber ranges from
about 0 to 5,000 psi in order to optimally provide expansion pressure while
minimizing the possibility of a catastrophic failure due to over
pressurization.
As illustrated in Fig. 14d, the apparatus 1700 is preferably positioned in
the wellbore 1600 with the tubular member 1715 positioned in an overlapping
relationship with the tubular casing 1620. In a particularly preferred
embodiment, the thin wall sections, 1640 and 1805, of the tubular casing 1620
and tubular member 1725 are positioned in opposing overlapping relation. In
this manner, the radial expansion of the tubular member 1725 will compress
the thin wall sections, 1640 and 1805, and annular compressible members, 1645
and 1745, into intimate contact.
After positioning of the apparatus 1700, a fluidic material 1825 is then
pumped into the fluid passage 1730. The fluidic material 1825 may comprise
any number of conventional commercially available materials such as, for
example, water, drilling mud, drilling gases, cement or epoxy. In a preferred
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embodiment, the fluidic material 1825 comprises a hardenable fluidic sealing
material such as, for example, cement in order to provide an outer annular
body
around the expanded tubular member 1715.
The fluidic material 1825 may be pumped into the fluid passage 1730 at
operating pressures and flow rates, for example, ranging from about 0 to 9,000
psi and 0 to 3,000 gallons/minute.
The fluidic material 1825 pumped into the fluid passage 1730 passes
through the fluid passage 1740 and outside of the apparatus 1700. The fluidic
material 1825 fills the annular region 1830 between the outside of the
apparatus 1700 and the interior walls of the wellbore 1600.
As illustrated in Fig. 14e, a plug 1835 is then introduced into the fluid
passage 1730. The plug 1835 lodges in the inlet to the fluid passage 1740
fluidicly isolating and blocking off the fluid passage 1730.
A fluidic material 1840 is then pumped into the fluid passage 1730. The
fluidic material 1840 may comprise any number of conventional commercially
available materials such as, for example, water, drilling mud or drilling
gases.
In a preferred embodiment, the fluidic material 1825 comprises a non-
hardenable fluidic material such as, for example, drilling mud or drilling
gases
in order to optimally provide pressurization of the pressure chamber 1755.
The fluidic material 1840 may be pumped into the fluid passage 1730 at
operating pressures and flow rates ranging, for example, from about 0 to 9,000
psi and 0 to 500 gallons/minute. In a preferred embodiment, the fluidic
material 1840 is pumped into the fluid passage 1730 at operating pressures and
flow rates ranging from about 500 to 5,000 psi and 0 to 500 gallons/minute in
order to optimally provide operating pressures and flow rates for radial
expansion.
The fluidic material 1840 pumped into the fluid passage 1730 passes
through the fluid passages 1735 and into the pressure chamber 1755.
Continued pumping of the fluidic material 1840 pressurizes the pressure
chamber 1755. The pressurization of the pressure chamber 1755 causes the
mandrel 1710 to move relative to the support member 1705 in the direction
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indicated by the arrows 1845. In this manner, the mandrel 1710 will cause the
tubular member 1715 to expand in the radial direction.
During the radial expansion process, the tubular member 1715 is
prevented from moving in an upward direction by the slips 1725. A length of
the tubular member 1715 is then expanded in the radial direction through the
pressurization of the pressure chamber 1755. The length of the tubular
member 1715 that is expanded during the expansion process will be
proportional to the stroke length of the mandrel 1710. Upon the completion of
a stroke, the operating pressure of the pressure chamber 1755 is then reduced
and the mandrel 1710 drops to it rest position with the tubular member 1715
supported by the mandrel 1715. The position of the support member 1705 may
be adjusted throughout the radial expansion process in order to maintain the
overlapping relationship between the thin walled sections, 1640 and 1805, of
the tubular casing 1620 and tubular member 1715. The stroking of the
mandrel 1710 is then repeated, as necessary, until the thin walled section
1805
of the tubular member 1715 is expanded into the thin walled section 1640 of
the
tubular casing 1620.
In a preferred embodiment, during the final stroke of the mandrel 1710,
the slips 1725 are positioned as close as possible to the thin walled section
1805
of the tubular member 1715 in order minimize slippage between the tubular
member 1715 and tubular casing 1620 at the end of the radial expansion
process. Alternatively, or in addition, the outside diameter of the first
compressive annular member 1745 is selected to ensure sufficient interference
fit with the tubular casing 1620 to prevent axial displacement of the tubular
member 1715 during the final stroke. Alternatively, or in addition, the
outside
diameter of the second compressive annular body 1750 is large enough to
provide an interference fit with the inside walls of the wellbore 1600 at an
earlier point in the radial expansion process so as to prevent further axial
displacement of the tubular member 1715. In this final alternative, the
interference fit is preferably selected to permit expansion of the tubular
member 1715 by pulling the mandrel 1710 out of the wellbore 1600, without
having to pressurize the pressure chamber 1755.
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During the radial expansion process, the pressurized areas of the
apparatus 1700 are limited to the fluid passages 1730 within the support
member 1705 and the pressure chamber 1755 within the mandrel 1710. No
fluid pressure acts directly on the tubular member 1715. This permits the use
of operating pressures higher than the tubular member 1715 could normally
withstand.
Once the tubular member 1715 has been completely expanded off of the
mandrel 1710, the support member 1705 and mandrel 1710 are removed from
the wellbore 1600. In a preferred embodiment, the contact pressure between
the deformed thin wall sections, 1640 and 1805, and compressible annular
members, 1645 and 1745, ranges from about 400 to 10,000 psi in order to
optimally support the tubular member 1715 using the tubular casing 1620.
In this manner, the tubular member 1715 is radially expanded into
contact with the tubular casing 1620 by pressurizing the interior of the fluid
passage 1730 and the pressure chamber 1755.
As illustrated in Fig. 14f, in a preferred embodiment, once the tubular
member 1715 is completely expanded in the radial direction by the mandrel
1710, the support member 1705 and mandrel 1710 are removed from the
wellbore 1600. In a preferred embodiment, the annular body of hardenable
fluidic material is then allowed to cure to form a rigid outer annular body
1850.
In the case where the tubular member 1715 is slotted, the hardenable fluidic
material will preferably permeate and envelop the expanded tubular member
1715.
The resulting new section of wellbore casing 1855 includes the expanded
tubular member 1715 and the rigid outer annular body 1850. The overlapping
joint 1860 between the tubular casing 1620 and the expanded tubular member
1715 includes the deformed thin wall sections, 1640 and 1805, and the
compressible annular bodies, 1645 and 1745. The inner diameter of the
resulting combined wellbore casings is substantially constant. In this manner,
a mono-diameter wellbore casing is formed. This process of expanding
overlapping tubular members having thin wall end portions with compressible
annular bodies into contact can be repeated for the entire length of a
wellbore.
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In this manner, a mono-diameter wellbore casing can be provided for thousands
of feet in a subterranean formation.
Referring now to Figures 15, 15a and 15b, an embodiment of an
apparatus 1900 for expanding a tubular member will be described. The
apparatus 1900 preferably includes a drillpipe 1905, an innerstring adapter
1910, a sealing sleeve 1915, an inner sealing mandrel 1920, an upper sealing
head 1925, a lower sealing head 1930, an outer sealing mandrel 1935, a load
mandrel 1940, an expansion cone 1945, a mandrel launcher 1950, a mechanical
slip body 1955, mechanical slips 1960, drag blocks 1965, casing 1970, and
fluid
passages 1975, 1980, 1985, and 1990.
The drillpipe 1905 is coupled to the innerstring adapter 1910. During
operation of the apparatus 1900, the drillpipe 1905 supports the apparatus
1900. The drillpipe 1905 preferably comprises a substantially hollow tubular
member or members. The drillpipe 1905 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular drillpipe, fiberglass or coiled tubing. In a preferred
embodiment, the drillpipe 1905 is fabricated from coiled tubing in order to
faciliate the placement of the apparatus 1900 in non-vertical wellbores. The
drillpipe 1905 may be coupled to the innerstring adapter 1910 using any
number of conventional commercially available mechanical couplings such as,
for example, drillpipe connectors, OCTG specialty type box and pin connectors,
a ratchet-latch type connector or a standard box by pin connector. In a
preferred embodiment, the drillpipe 1905 is removably coupled to the
innerstring adapter 1910 by a drillpipe connection.
The drillpipe 1905 preferably includes a fluid passage 1975 that is
adapted to convey fluidic materials from a surface location into the fluid
passage 1980. In a preferred embodiment, the fluid passage 1975 is adapted to
convey fluidic materials such as, for example, cement, drilling mud, epoxy or
lubricants at operating pressures and flow rates ranging from about 0 to 9,000
psi and 0 to 3,000 gallons/minute.
The innerstring adapter 1910 is coupled to the drill string 1905 and the
sealing sleeve 1915. The innerstring adapter 1910 preferably comprises a
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substantially hollow tubular member or members. The innerstring adapter
1910 may be fabricated from any number of conventional commercially
available materials such as, for example, oil country tubular goods, low alloy
steel, carbon steel, stainless steel or other high strength materials. In a
preferred embodiment, the innerstring adapter 1910 is fabricated from oilfield
country tubular goods in order to optimally provide mechanical properties that
closely match those of the drill string 1905.
The innerstring adapter 1910 may be coupled to the drill string 1905
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connectors, oilfield country tubular goods
specialty type threaded connectors, ratchet-latch type stab in connector, or a
standard threaded connection. In a preferred embodiment, the innerstring
adapter 1910 is removably coupled to the drill pipe 1905 by a drillpipe
connection. The innerstring adapter 1910 may be coupled to the sealing sleeve
1915 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connector, ratchet-latch type stab in
connectors,
or a standard threaded connection. In a preferred embodiment, the innerstring
adapter 1910 is removably coupled to the sealing sleeve 1915 by a standard
threaded connection.
The innerstring adapter 1910 preferably includes a fluid passage 1980
that is adapted to convey fluidic materials from the fluid passage 1975 into
the
fluid passage 1985. In a preferred embodiment, the fluid passage 1980 is
adapted to convey fluidic materials such as, for example, cement, drilling
mud,
epoxy, or lubricants at operating pressures and flow rates ranging from about
0
to 9,000 psi and 0 to 3,000 gallons/minute.
The sealing sleeve 1915 is coupled to the innerstring adapter 1910 and
the inner sealing mandrel 1920. The sealing sleeve 1915 preferably comprises a
substantially hollow tubular member or members. The sealing sleeve 1915 may
be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, carbon steel,
low
alloy steel, stainless steel or other high strength materials. In a preferred
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embodiment, the sealing sleeve 1915 is fabricated from oilfield country
tubular
goods in order to optimally provide mechanical properties that substantially
match the remaining components of the apparatus 1900.
The sealing sleeve 1915 may be coupled to the innerstring adapter 1910
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type stab in connection, or
a
standard threaded connection. In a preferred embodiment, the sealing sleeve
1915 is removably coupled to the innerstring adapter 1910 by a standard
threaded connection. The sealing sleeve 1915 may be coupled to the inner
sealing mandrel 1920 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, or a standard threaded
connection. In a preferred embodiment, the sealing sleeve 1915 is removably
coupled to the inner sealing mandrel 1920 by a standard threaded connection.
The sealing sleeve 1915 preferably includes a fluid passage 1985 that is
adapted to convey fluidic materials from the fluid passage 1980 into the fluid
passage 1990. In a preferred embodiment, the fluid passage 1985 is adapted to
convey fluidic materials such as, for example, cement, drilling mud, epoxy or
lubricants at operating pressures and flow rates ranging from about 0 to 9,000
psi and 0 to 3,000 gallons/minute.
The inner sealing mandrel 1920 is coupled to the sealing sleeve 1915 and
the lower sealing head 1930. The inner sealing mandrel 1920 preferably
comprises a substantially hollow tubular member or members. The inner
sealing mandrel 1920 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, stainless steel, low alloy steel, carbon steel or other similar high
strength
materials. In a preferred embodiment, the inner sealing mandrel 1920 is
fabricated from stainless steel in order to optimally provide mechanical
properties similar to the other components of the apparatus 1900 while also
providing a smooth outer surface to support seals and other moving parts that
can operate with minimal wear, corrosion and pitting.
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The inner sealing mandrel 1920 may be coupled to the sealing sleeve
1915 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, or a standard threaded connection .
In a preferred embodiment, the inner sealing mandrel 1920 is removably
coupled to the sealing sleeve 1915 by a standard threaded connections. The
inner sealing mandrel 1920 may be coupled to the lower sealing head 1930'
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type stab in connectors or
standard threaded connections. In a preferred embodiment, the inner sealing
mandrel 1920 is removably coupled to the lower sealing head 1930 by a
standard threaded connections connection.
The inner sealing mandrel 1920 preferably includes a fluid passage 1990
that is adapted to convey fluidic materials from the fluid passage 1985 into
the
fluid passage 1995. In a preferred embodiment, the fluid passage 1990 is
adapted to convey fluidic materials such as, for example, cement, drilling
mud,
epoxy or lubricants at operating pressures and flow rates ranging from about 0
to 9,000 psi and 0 to 3,000 gallons/minute.
The upper sealing head 1925 is coupled to the outer sealing mandrel 1935
and the expansion cone 1945. The upper sealing head 1925 is also movably
coupled to the outer surface of the inner sealing mandrel 1920 and the inner
surface of the casing 1970. In this manner, the upper sealing head 1925, outer
sealing mandrel 1935, and the expansion cone 1945 reciprocate in the axial
direction. The radial clearance between the inner cylindrical surface of the
upper sealing head 1925 and the outer surface of the inner sealing mandrel
1920 may range, for example, from about 0.025 to 0.05 inches. In a preferred
embodiment, the radial clearance between the inner cylindrical surface of the
upper sealing head 1925 and the outer surface of the inner sealing mandrel
1920 ranges from about 0.005 to 0.01 inches in order to optimally provide
clearance for pressure seal placement. The radial clearance between the outer
cylindrical surface of the upper sealing head 1925 and the inner surface of
the
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casing 1970 may range, for example, from about 0.025 to 0.375 inches. In a
preferred embodiment, the radial clearance between the outer cylindrical
surface of the upper sealing head 1925 and the inner surface of the casing
1970
ranges from about 0.025 to 0.125 inches in order to optimally provide
stabilization for the expansion cone 1945 as the expansion cone 1945 is
upwardly moved inside the casing 1970.
The upper sealing head 1925 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The upper sealing
head 1925 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods,
stainless steel, machine tool steel, or similar high strength materials. In a
preferred embodiment, the upper sealing head 1925 is fabricated from stainless
steel in order to optimally provide high strength and smooth outer surfaces
that
are resistant to wear, galling, corrosion and pitting.
The inner surface of the upper sealing head 1925 preferably includes one
or more annular sealing members 2000 for sealing the interface between the
upper sealing head 1925 and the inner sealing mandrel 1920. The sealing
members 2000 may comprise any number of conventional commercially
available annular sealing members such as, for example, o-rings, polypak seals
or metal spring energized seals. In a preferred embodiment, the sealing
members 2000 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for a long axial motion.
In a preferred embodiment, the upper sealing head 1925 includes a
shoulder 2005 for supporting the upper sealing head 1925 on the lower sealing
head 1930.
The upper sealing head 1925 may be coupled to the outer sealing
mandrel 1935 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, or a standard threaded
connections. In a preferred embodiment, the upper sealing head 1925 is
removably coupled to the outer sealing mandrel 1935 by a standard threaded
connections. In a preferred embodiment, the mechanical coupling between the
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upper sealing head 1925 and the outer sealing mandrel 1935 includes one or
more sealing members 2010 for fluidicly sealing the interface between the
upper
sealing head 1925 and the outer sealing mandrel 1935. The sealing members
2010 may comprise any number of conventional commercially available sealing
members such as, for example, o-rings, polypak seals or metal spring energized
seals. In a preferred embodiment, the sealing members 2010 comprise polypak
seals available from Parker Seals in order to optimally provide sealing for a
long
axial stroking motion.
The lower sealing head 1930 is coupled to the inner sealing mandrel 1920
and the load mandrel 1940. The lower sealing head 1930 is also movably
coupled to the inner surface of the outer sealing mandrel 1935. In this
manner,
the upper sealing head 1925 and outer sealing mandrel 1935 reciprocate in the
axial direction. The radial clearance between the outer surface of the lower
sealing head 1930 and the inner surface of the outer sealing mandrel 1935 may
range, for example, from about 0.025 to 0.05 inches. In a preferred
embodiment, the radial clearance between the outer surface of the lower
sealing
head 1930 and the inner surface of the outer sealing mandrel 1935 ranges from
about 0.005 to 0.010 inches in order to optimally provide a close tolerance
having room for the installation of pressure seal rings.
The lower sealing head 1930 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The lower sealing
head 1930 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods,
stainless steel, machine tool steel or other similar high strength materials.
In a
preferred embodiment, the lower sealing head 1930 is fabricated from stainless
steel in order to optimally provide high strength and resistance to wear,
galling,
corrosion, and pitting.
The outer surface of the lower sealing head 1930 preferably includes one
or more annular sealing members 2015 for sealing the interface between the
lower sealing head 1930 and the outer sealing mandrel 1935. The sealing
members 2015 may comprise any number of conventional commercially
available annular sealing members such as, for example, o-rings, polypak
seals,
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or metal spring energized seals. In a preferred embodiment, the sealing
members 2015 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for a long axial stroke.
The lower sealing head 1930 may be coupled to the inner sealing mandrel
1920 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, welding, amorphous bonding or a
standard threaded connection. In a preferred embodiment, the lower sealing
head 1930 is removably coupled to the inner sealing mandrel 1920 by a
standard threaded connection.
In a preferred embodiment, the mechanical coupling between the lower
sealing head 1930 and the inner sealing mandrel 1920 includes one or more
sealing members 2020 for fluidicly sealing the interface between the lower
sealing head 1930 and the inner sealing mandrel 1920. The sealing members
2020 may comprise any number of conventional commercially available sealing
members such as, for example, o-rings, polypak seals, or metal spring
energized
seals. In a preferred embodiment, the sealing members 2020 comprise polypak
seals available from Parker Seals in order to optimally provide sealing for a
long
axial motion.
The lower sealing head 1930 may be coupled to the load mandrel 1940
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connections, welding, amorphous bonding or a standard
threaded connection. In a preferred embodiment, the lower sealing head 1930
is removably coupled to the load mandrel 1940 by a standard threaded
connection. In a preferred embodiment, the mechanical coupling between the
lower sealing head 1930 and the load mandrel 1940 includes one or more
sealing members 2025 for fluidicly sealing the interface between the lower
sealing head 1930 and the load mandrel 1940. The sealing members 2025 may
comprise any number of conventional commercially available sealing members
such as, for example, o-rings, polypak seals, or metal spring energized seals.
In
a preferred embodiment, the sealing members 2025 comprise polypak seals
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available from Parker Seals in order to optimally provide sealing for a long
axial
stroke.
In a preferred embodiment, the lower sealing head 1930 includes a throat
passage 2040 fluidicly coupled between the fluid passages 1990 and 1995. The
throat passage 2040 is preferably of reduced size and is adapted to receive
and
engage with a plug 2045, or other similar device. In this manner, the fluid
passage 1990 is fluidicly isolated from the fluid passage 1995. In this
manner,
the pressure chamber 2030 is pressurized.
The outer sealing mandrel 1935 is coupled to the upper sealing head 1925
and the expansion cone 1945. The outer sealing mandrel 1935 is also movably
coupled to the inner surface of the casing 1970 and the outer surface of the
lower sealing head 1930. In this manner, the upper sealing head 1925, outer
sealing mandrel 1935, and the expansion cone 1945 reciprocate in the axial
direction. The radial clearance between the outer surface of the outer sealing
mandrel 1935 and the inner surface of the casing 1970 may range, for example,
from about 0.025 to 0.375 inches. In a preferred embodiment, the radial
clearance between the outer surface of the outer sealing mandrel 1935 and the
inner surface of the casing 1970 ranges from about 0.025 to 0.125 inches in
order to optimally provide maximum piston surface area to maximize the radial
expansion force. The radial clearance between the inner surface of the outer
sealing mandrel 1935 and the outer surface of the lower sealing head 1930 may
range, for example, from about 0.025 to 0.05 inches. In a preferred
embodiment, the radial clearance between the inner surface of the outer
sealing
mandrel 1935 and the outer surface of the lower sealing head 1930 ranges from
about 0.005 to 0.010 inches in order to optimally provide a minimum gap for
the
sealing elements to bridge and seal.
The outer sealing mandrel 1935 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The outer
sealing mandrel 1935 may be fabricated from any number of conventional
commercially available materials such as, for example, low alloy steel, carbon
steel, 13 chromium steel or stainless steel. In a preferred embodiment, the
outer sealing mandrel 1935 is fabricated from stainless steel in order to
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optimally provide maximum strength and minimum wall thickness while also
providing resistance to corrosion, galling and pitting.
The outer sealing mandrel 1935 may be coupled to the upper sealing
head 1925 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, standard threaded connections, or
welding. In a preferred embodiment, the outer sealing mandrel 1935 is
removably coupled to the upper sealing head 1925 by a standard threaded
connections connection. The outer sealing mandrel 1935 may be coupled to the
expansion cone 1945 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, or a standard threaded
connections connection, or welding. In a preferred embodiment, the outer
sealing mandrel 1935 is removably coupled to the expansion cone 1945 by a
standard threaded connections connection.
The upper sealing head 1925, the lower sealing head 1930, the inner
sealing mandrel 1920, and the outer sealing mandrel 1935 together define a
pressure chamber 2030. The pressure chamber 2030 is fluidicly coupled to the
passage 1990 via one or more passages 2035. During operation of the apparatus
1900, the plug 2045 engages with the throat passage 2040 to fluidicly isolate
the
fluid passage 1990 from the fluid passage 1995. The pressure chamber 2030 is
then pressurized which in turn causes the upper sealing head 1925, outer
sealing mandrel 1935, and expansion cone 1945 to reciprocate in the axial
direction. The axial motion of the expansion cone 1945 in turn expands the
casing 1970 in the radial direction.
The load mandrel 1940 is coupled to the lower sealing head 1930 and the
mechanical slip body 1955. The load mandrel 1940 preferably comprises an
annular member having substantially cylindrical inner and outer surfaces. The
load mandrel 1940 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
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materials. In a preferred embodiment, the load mandrel 1940 is fabricated from
oilfield country tubular goods in order to optimally provide high strength.
The load mandrel 1940 may be coupled to the lower sealing head 1930
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, welding, amorphous bonding or a standard
threaded connection. In a preferred embodiment, the load mandrel 1940 is
removably coupled to the lower sealing head 1930 by a standard threaded
connection. The load mandrel 1940 may be coupled to the mechanical slip body
1955 using any number of conventional commercially available mechanical
couplings such as, for example, a drillpipe connection, oilfield country
tubular
goods specialty type threaded connections, welding, amorphous bonding, or a
standard threaded connections connection. In a preferred embodiment, the
load mandrel 1940 is removably coupled to the mechanical slip body 1955 by a
standard threaded connections connection.
The load mandrel 1940 preferably includes a fluid passage 1995 that is
adapted to convey fluidic materials from the fluid passage 1990 to the region
outside of the apparatus 1900. In a preferred embodiment, the fluid passage
1995 is adapted to convey fluidic materials such as, for example, cement,
epoxy,
water, drilling mud, or lubricants at operating pressures and flow rates
ranging
from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The expansion cone 1945 is coupled to the outer sealing mandrel 1935.
The expansion cone 1945 is also movably coupled to the inner surface of the
casing 1970. In this manner, the upper sealing head 1925, outer sealing
mandrel 1935, and the expansion cone 1945 reciprocate in the axial direction.
The reciprocation of the expansion cone 1945 causes the casing 1970 to expand
in the radial direction.
The expansion cone 1945 preferably comprises an annular member
having substantially cylindrical inner and conical outer surfaces. The outside
radius of the outside conical surface may range, for example, from about 2 to
34
inches. In a preferred embodiment, the outside radius of the outside conical
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surface ranges from about 3 to 28 inches in order to optimally provide cone
dimensions for the typical range of tubular members.
The axial length of the expansion cone 1945 may range, for example,
from about 2 to 8 times the largest outer diameter of the expansion cone 1945.
In a preferred embodiment, the axial length of the expansion cone 1945 ranges
from about 3 to 5 times the largest outer diameter of the expansion cone 1945
in order to optimally provide stability and centralization of the expansion
cone
1945 during the expansion process. In a preferred embodiment, the angle of
attack of the expansion cone 1945 ranges from about 5 to 30 degrees in order
to
optimally balance friction forces with the desired amount of radial expansion.
The expansion cone 1945 angle of attack will vary as a function of the
operating
parameters of the particular expansion operation.
The expansion cone 1945 may be fabricated from any number of
conventional commercially available materials such as, for example, machine
tool steel, ceramics, tungsten carbide, nitride steel, or other similar high
strength materials. In a preferred embodiment, the expansion cone 1945 is
fabricated from D2 machine tool steel in order to optimally provide high
strength and resistance to corrosion, wear, galling, and pitting. In a
particularly preferred embodiment, the outside surface of the expansion cone
1945 has a surface hardness ranging from about 58 to 62 Rockwell C in order to
optimally provide high strength and resist wear and galling.
The expansion cone 1945 may be coupled to the outside sealing mandrel
1935 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield tubular country
goods specialty type threaded connection, welding, amorphous bonding, or a
standard threaded connections connection. In a preferred embodiment, the
expansion cone 1945 is coupled to the outside sealing mandrel 1935 using a
standard threaded connections connection in order to optimally provide
connector strength for the typical operating loading conditions while also
permitting easy replacement of the expansion cone 1945.
The mandrel launcher 1950 is coupled to the casing 1970. The mandrel
launcher 1950 comprises a tubular section of casing having a reduced wall
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thickness compared to the casing 1970. In a preferred embodiment, the wall
thickness of the mandrel launcher is about 50 to 100 % of the wall thickness
of
the casing 1970. In this manner, the initiation of the radial expansion of the
casing 1970 is facilitated, and the insertion of the larger outside diameter
mandrel launcher 1950 into the wellbore and/or casing is facilitated.
The mandrel launcher 1950 may be coupled to the casing 1970 using any
number of conventional mechanical couplings. The mandrel launcher 1950 may
have a wall thickness ranging, for example, from about 0.15 to 1.5 inches. In
a
preferred embodiment, the wall thickness of the mandrel launcher 1950 ranges
from about 0.25 to 0.75 inches in order to optimally provide high strength
with
a small overall profile. The mandrel launcher 1950 may be fabricated from any
number of conventional commercially available materials such as, for example,
oil field tubular goods, low alloy steel, carbon steel, stainless steel or
other
similar high strength materials. In a preferred embodiment, the mandrel
launcher 1950 is fabricated from oil field tubular goods of higher strength
but
lower wall thickness than the casing 1970 in order to optimally provide a thin
walled container with approximately the same burst strength as the casing
1970.
The mechanical slip body 1955 is coupled to the load mandrel 1970, the
mechanical slips 1960, and the drag blocks 1965. The mechanical slip body
1955 preferably comprises a tubular member having an inner passage 2050
fluidicly coupled to the passage 1995. In this manner, fluidic materials may
be
conveyed from the passage 2050 to a region outside of the apparatus 1900.
The mechanical slip body 1955 may be coupled to the load mandrel 1940
using any number of conventional mechanical couplings. In a preferred
embodiment, the mechanical slip body 1955 is removably coupled to the load
mandrel 1940 using a standard threaded connection in order to optimally
provide high strength and permit the mechanical slip body 1955 to be easily
replaced. The mechanical slip body 1955 may be coupled to the mechanical slips
1955 using any number of conventional mechanical couplings. In a preferred
embodiment, the mechanical slip body 1955 is removably coupled to the
mechanical slips 1955 using threads and sliding steel retainer rings in order
to
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optimally provide high strength coupling and also permit easy replacement of
the mechanical slips 1955. The mechanical slip body 1955 may be coupled to
the drag blocks 1965 using any number of conventional mechanical couplings.
In a preferred embodiment, the mechanical slip body 1955 is removably coupled
to the drag blocks 1965 using threaded connections and sliding steel retainer
rings in order to optimally provide high strength and also permit easy
replacement of the drag blocks 1965.
The mechanical slips 1960 are coupled to the outside surface of the
mechanical slip body 1955. During operation of the apparatus 1900, the
mechanical slips 1960 prevent upward movement of the casing 1970 and
mandrel launcher 1950. In this manner, during the axial reciprocation of the
expansion cone 1945, the casing 1970 and mandrel launcher 1950 are
maintained in a substantially stationary position. In this manner, the mandrel
launcher 1950 and casing 1970 are expanded in the radial direction by the
axial
movement of the expansion cone 1945.
The mechanical slips 1960 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer
tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or
Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In a
preferred embodiment, the mechanical slips 1960 comprise RTTS packer
tungsten carbide mechanical slips available from Halliburton Energy Services
in order to optimally provide resistance to axial movement of the casing 1970
during the expansion process.
The drag blocks 1965 are coupled to the outside surface of the mechanical
slip body 1955. During operation of the apparatus 1900, the drag blocks 1965
prevent upward movement of the casing 1970 and mandrel launcher 1950. In
this manner, during the axial reciprocation of the expansion cone 1945, the
casing 1970 and mandrel launcher 1950 are maintained in a substantially
stationary position. In this manner, the mandrel launcher 1950 and casing
1970 are expanded in the radial direction by the axial movement of the
expansion cone 1945.
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The drag blocks 1965 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer
tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or
Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In a
preferred embodiment, the drag blocks 1965 comprise RTTS packer tungsten
carbide mechanical slips available from Halliburton Energy Services in order
to
optimally provide resistance to axial movement of the casing 1970 during the
expansion process.
The casing 1970 is coupled to the mandrel launcher 1950. The casing
1970 is further removably coupled to the mechanical slips 1960 and drag blocks
1965. The casing 1970 preferably comprises a tubular member. The casing
1970 may be fabricated from any number of conventional commercially
available materials such as, for example, slotted tubulars, oil field country
tubular goods, low alloy steel, carbon steel, stainless steel or other similar
high
strength materials. In a preferred embodiment, the casing 1970 is fabricated
from oilfield country tubular goods available from various foreign and
domestic
steel mills in order to optimally provide high strength. In a preferred
embodiment, the upper end of the casing 1970 includes one or more sealing
members positioned about the exterior of the casing 1970.
During operation, the apparatus 1900 is positioned in a wellbore with the
upper end of the casing 1970 positioned in an overlapping relationship within
an existing wellbore casing. In order minimize surge pressures within the
borehole during placement of the apparatus 1900, the fluid passage 1975 is
preferably provided with one or more pressure relief passages. During the
placement of the apparatus 1900 in the wellbore, the casing 1970 is supported
by the expansion cone 1945.
After positioning of the apparatus 1900 within the bore hole in an
overlapping relationship with an existing section of wellbore casing, a first
fluidic material is pumped into the fluid passage 1975 from a surface
location.
The first fluidic material is conveyed from the fluid passage 1975 to the
fluid
passages 1980, 1985, 1990, 1995, and 2050. The first fluidic material will
then
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exit the apparatus and fill the annular region between the outside of the
apparatus 1900 and the interior walls of the bore hole.
The first fluidic material may comprise any number of conventional
commercially available materials such as, for example, drilling mud, water,
epoxy or cement. In a preferred embodiment, the first fluidic material
comprises a hardenable fluidic sealing material such as, for example, cement
or
epoxy. In this manner, a wellbore casing having an outer annular layer of a
hardenable material may be formed.
The first fluidic material may be pumped into the apparatus 1900 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi, and 0 to 3,000 gallons/minute. In a preferred embodiment, the first
fluidic
material is pumped into the apparatus 1900 at operating pressures and flow
rates ranging from about 0 to 4,500 psi and 0 to 3,000 gallons/minute in order
to optimally provide operating pressures and flow rates for typical operating
conditions.
At a predetermined point in the injection of the first fluidic material such
as, for example, after the annular region outside of the apparatus 1900 has
been
filled to a predetermined level, a plug 2045, dart, or other similar device is
introduced into the first fluidic material. The plug 2045 lodges in the throat
passage 2040 thereby fluidicly isolating the fluid passage 1990 from the fluid
passage 1995.
After placement of the plug 2045 in the throat passage 2040, a second
fluidic material is pumped into the fluid passage 1975 in order to pressurize
the
pressure chamber 2030. The second fluidic material may comprise any number
of conventional commercially available materials such as, for example, water,
drilling gases, drilling mud or lubricant. In a preferred embodiment, the
second
fluidic material comprises a non-hardenable fluidic material such as, for
example, water, drilling mud or lubricant in order minimize frictional forces.
The second fluidic material may be pumped into the apparatus 1900 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi and 0 to 4,500 gallons/minute. In a preferred embodiment, the second
fluidic material is pumped into the apparatus 1900 at operating pressures and
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flow rates ranging from about 0 to 3,500 psi, and 0 to 1,200 gallons/minute in
order to optimally provide expansion of the casing 1970.
The pressurization of the pressure chamber 2030 causes the upper
sealing head 1925, outer sealing mandrel 1935, and expansion cone 1945 to
move in an axial direction. As the expansion cone 1945 moves in the axial
direction, the expansion cone 1945 pulls the mandrel launcher 1950 and drag
blocks 1965 along, which sets the mechanical slips 1960 and stops further
axial
movement of the mandrel launcher 1950 and casing 1970. In this manner, the
axial movement of the expansion cone 1945 radially expands the mandrel
launcher 1950 and casing 1970.
Once the upper sealing head 1925, outer sealing mandrel 1935, and
expansion cone 1945 complete an axial stroke, the operating pressure of the
second fluidic material is reduced and the drill string 1905 is raised. This
causes the inner sealing mandrel 1920, lower sealing head 1930, load mandrel
1940, and mechanical slip body 1955 to move upward. This unsets the
mechanical slips 1960 and permits the mechanical slips 1960 and drag blocks
1965 to be moved upward within the mandrel launcher and casing 1970. When
the lower sealing head 1930 contacts the upper sealing head 1925, the second
fluidic material is again pressurized and the radial expansion process
continues.
In this manner, the mandrel launcher 1950 and casing 1970 are radial
expanded through repeated axial strokes of the upper sealing head 1925, outer
sealing mandrel 1935 and expansion cone 1945. Throughput the radial
expansion process, the upper end of the casing 1970 is preferably maintained
in
an overlapping relation with an existing section of wellbore casing.
At the end of the radial expansion process, the upper end of the casing
1970 is expanded into intimate contact with the inside surface of the lower
end
of the existing wellbore casing. In a preferred embodiment, the sealing
members provided at the upper end of the casing 1970 provide a fluidic seal
between the outside surface of the upper end of the casing 1970 and the inside
surface of the lower end of the existing wellbore casing. In a preferred
embodiment, the contact pressure between the casing 1970 and the existing
section of wellbore casing ranges from about 400 to 10,000 psi in order to
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optimally provide contact pressure for activating sealing members, provide
optimal resistance to axial movement of the expanded casing 1970, and
optimally support typical tensile and compressive loads.
In a preferred embodiment, as the expansion cone 1945 nears the end of
the casing 1970, the operating flow rate of the second fluidic material is
reduced
in order to minimize shock to the apparatus 1900. In an alternative
embodiment, the apparatus 1900 includes a shock absorber for absorbing the
shock created by the completion of the radial expansion of the casing 1970.
In a preferred embodiment, the reduced operating pressure of the second
fluidic material ranges from about 100 to 1,000 psi as the expansion cone 1945
nears the end of the casing 1970 in order to optimally provide reduced axial
movement and velocity of the expansion cone 1945. In a preferred embodiment,
the operating pressure of the second fluidic material is reduced during the
return stroke of the apparatus 1900 to the range of about 0 to 500 psi in
order
minimize the resistance to the movement of the expansion cone 1945. In a
preferred embodiment, the stroke length of the apparatus 1900 ranges from
about 10 to 45 feet in order to optimally provide equipment lengths that can
be
handled by typical oil well rigging equipment while also minimizing the
frequency at which the expansion cone 1945 must be stopped so the apparatus
1900 can be re-stroked for further expansion operations.
In an alternative embodiment, at least a portion of the upper sealing
head 1925 includes an expansion cone for radially expanding the mandrel
launcher 1950 and casing 1970 during operation of the apparatus 1900 in order
to increase the surface area of the casing 1970 acted upon during the radial
expansion process. In this manner, the operating pressures can be reduced.
In an alternative embodiment, mechanical slips are positioned in an axial
location between the sealing sleeve 1915 and the inner sealing mandrel 1920 in
order to simplify the operation and assembly of the apparatus 1900.
Upon the complete radial expansion of the casing 1970, if applicable, the
first fluidic material is permitted to cure within the annular region between
the
outside of the expanded casing 1970 and the interior walls of the wellbore. In
the case where the expanded casing 1970 is slotted, the cured fluidic material
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will preferably permeate and envelop the expanded casing. In this manner, a
new section of wellbore casing is formed within a wellbore. Alternatively, the
apparatus 1900 may be used to join a first section of pipeline to an existing
section of pipeline. Alternatively, the apparatus 1900 may be used to
directl~~
line the interior of a wellbore with a casing, without the use of an outer
annular
layer of a hardenable material. Alternatively, the apparatus 1900 may be used
to expand a tubular support member in a hole.
During the radial expansion process, the pressurized areas of the
apparatus 1900 are limited to the fluid passages 1975, 1980, 1985, and 1990,
and the pressure chamber 2030. No fluid pressure acts directly on the mandrel
launcher 1950 and casing 1970. This permits the use of operating pressures
higher than the mandrel launcher 1950 and casing 1970 could normally
withstand.
Referring now to Figure 16, a preferred embodiment of an apparatus
2100 for forming a mono-diameter wellbore casing will be described. The
apparatus 2100 preferably includes a drillpipe 2105, an innerstring adapter
2110, a sealing sleeve 2115, an inner sealing mandrel 2120, slips 2125, upper
sealing head 2130, lower sealing head 2135, outer sealing mandrel 2140, load
mandrel 2145, expansion cone 2150, and casing 2155.
The drillpipe 2105 is coupled to the innerstring adapter 2110. During
operation of the apparatus 2100, the drillpipe 2105 supports the apparatus
2100. The drillpipe 2105 preferably comprises a substantially hollow tubular
member or members. The drillpipe 2105 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other
similar high strength material. In a preferred embodiment, the drillpipe 2105
is
fabricated from coiled tubing in order to faciliate the placement of the
apparatus 1900 in non-vertical wellbores. The drillpipe 2105 may be coupled to
the innerstring adapter 2110 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty type threaded connection, ratchet-
latch
type connection, or a standard threaded connection. In a preferred
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embodiment, the drillpipe 2105 is removably coupled to the innerstring adapter
2110 by a drill pipe connection.
The drillpipe 2105 preferably includes a fluid passage 2160 that is
adapted to convey fluidic materials from a surface location into the fluid
passage 2165. In a preferred embodiment, the fluid passage 2160 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud or lubricants at operating pressures and flow rates ranging from about 0
to
9,000 psi and 0 to 3,000 gallons/minute.
The innerstring adapter 2110 is coupled to the drill string 2105 and the
sealing sleeve 2115. The innerstring adapter 2110 preferably comprises a
substantially hollow tubular member or members. The innerstring adapter
2110 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel or other similar high strength
materials.
In a preferred embodiment, the innerstring adapter 2110 is fabricated from
stainless steel in order to optimally provide high strength, low friction, and
resistance to corrosion and wear.
The innerstring adapter 2110 may be coupled to the drill string 2105
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type connection or a
standard
threaded connection. In a preferred embodiment, the innerstring adapter 2110
is removably coupled to the drill pipe 2105 by a drillpipe connection. The
innerstring adapter 2110 may be coupled to the sealing sleeve 2115 using any
number of conventional commercially available mechanical couplings such as,
for example, drillpipe connection, oilfield country tubular goods specialty
type
threaded connection, ratchet-latch type threaded connection, or a standard
threaded connection. In a preferred embodiment, the innerstring adapter 2110
is removably coupled to the sealing sleeve 2115 by a standard threaded
connection.
The innerstring adapter 2110 preferably includes a fluid passage 2165
that is adapted to convey fluidic materials from the fluid passage 2160 into
the
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fluid passage 2170. In a preferred embodiment, the fluid passage 2165 is
adapted to convey fluidic materials such as, for example, cement, epoxy, water
drilling muds, or lubricants at operating pressures and flow rates ranging
from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The sealing sleeve 2115 is coupled to the innerstring adapter 2110 and
the inner sealing mandrel 2120. The sealing sleeve 2115 preferably comprises a
substantially hollow tubular member or members. The sealing sleeve 2115 may
be fabricated from any number of conventional commercially available
materials such as, for example, oil field tubular goods, low alloy steel,
carbon
steel, stainless steel or other similar high strength materials. In a
preferred
embodiment, the sealing sleeve 2115 is fabricated from stainless steel in
order
to optimally provide high strength, low friction surfaces, and resistance to
corrosion, wear, galling, and pitting.
The sealing sleeve 2115 may be coupled to the innerstring adapter 2110
using any number of conventional commercially available mechanical couplings
such as, for example, a standard threaded connection, oilfield country tubular
goods specialty type threaded connections, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the sealing sleeve
2115 is removably coupled to the innerstring adapter 2110 by a standard
threaded connection. The sealing sleeve 2115 may be coupled to the inner
sealing mandrel 2120 using any number of conventional commercially available
mechanical couplings such as, for example, a standard threaded connection,
oilfield country tubular goods specialty type threaded connections, welding,
amorphous bonding, or a standard threaded connection. In a preferred
embodiment, the sealing sleeve 2115 is removably coupled to the inner sealing
mandrel 2120 by a standard threaded connection.
The sealing sleeve 2115 preferably includes a fluid passage 21?0 that is
adapted to convey fluidic materials from the fluid passage 2165 into the fluid
passage 2175. In a preferred embodiment, the fluid passage 2170 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud, or lubricants at operating pressures and flow rates ranging from about 0
to 9,000 psi and 0 to 3,000 gallons/minute.
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The inner sealing mandrel 2120 is coupled to the sealing sleeve 2115,
slips 2125, and the lower sealing head 2135. The inner sealing mandrel 2120
preferably comprises a substantially hollow tubular member or members. The
inner sealing mandrel 2120 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the inner sealing mandrel 2120 is
fabricated from stainless steel in order to optimally provide high strength,
low
friction surfaces, and corrosion and wear resistance.
The inner sealing mandrel 2120 may be coupled to the sealing sleeve
2115 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, or a standard threaded connection.
In a preferred embodiment, the inner sealing mandrel 2120 is removably
coupled to the sealing sleeve 2115 by a standard threaded connection. The
standard threaded connection provides high strength and permits easy
replacement of components. The inner sealing mandrel 2120 may be coupled to
the slips 2125 using any number of conventional commercially available
mechanical couplings such as, for example, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the inner sealing
mandrel 2120 is removably coupled to the slips 2125 by a standard threaded
connection. The inner sealing mandrel 2120 may be coupled to the lower
sealing head 2135 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, welding, amorphous bonding
or a standard threaded connection. In a preferred embodiment, the inner
sealing mandrel 2120 is removably coupled to the lower sealing head 2135 by a
standard threaded connection.
The inner sealing mandrel 2120 preferably includes a fluid passage 2175
that is adapted to convey fluidic materials from the fluid passage 2170 into
the
fluid passage 2180. In a preferred embodiment, the fluid passage 2175 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
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drilling mud or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The slips 2125 are coupled to the outer surface of the inner sealing
mandrel 2120. During operation of the apparatus 2100, the slips 2125
preferably maintain the casing 2155 in a substantially stationary position
during the radial expansion of the casing 2155. In a preferred embodiment, the
slips 2125 are activated using the fluid passages 2185 to convey pressurized
fluid material into the slips 2125.
The slips 2125 may comprise any number of commercially available
hydraulic slips such as, for example, RTTS packer tungsten carbide hydraulic
slips or Model 3L retrievable bridge plug hydraulic slips. In a preferred
embodiment, the slips 2125 comprise RTTS packer tungsten carbide hydraulic
slips available from Halliburton Energy Services in order to optimally provide
resistance to axial movement of the casing 2155 during the expansion process.
In a particularly preferred embodiment, the slips include a fluid passage
2190,
pressure chamber 2195, spring return 2200, and slip member 2205.
The slips 2125 may be coupled to the inner sealing mandrel 2120 using
any number of conventional mechanical couplings. In a preferred embodiment,
the slips 2125 are removably coupled to the outer surface of the inner sealing
mandrel 2120 by a thread connection in order to optimally provide
interchangeability of parts.
The upper sealing head 2130 is coupled to the outer sealing mandrel 2140
and expansion cone 2150. The upper sealing head 2130 is also movably coupled
to the outer surface of the inner sealing mandrel 2120 and the inner surface
of
the casing 2155. In this manner, the upper sealing head 2130 reciprocates in
the axial direction. The radial clearance between the inner cylindrical
surface
of the upper sealing head 2130 and the outer surface of the inner sealing
mandrel 2120 may range, for example, from about 0.025 to 0.05 inches. In a
preferred embodiment, the radial clearance between the inner cylindrical
surface of the upper sealing head 2130 and the outer surface of the inner
sealing mandrel 2120 ranges from about 0.005 to 0.010 inches in order to
optimally provide a pressure seal. The radial clearance between the outer
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cylindrical surface of the upper sealing head 2130 and the inner surface of
the
casing 2155 may range, for example, from about 0.025 to 0.375 inches. In a
preferred embodiment, the radial clearance between the outer cylindrical
surface of the upper sealing head 2130 and the inner surface of the casing
2155
ranges from about 0.025 to 0.125 inches in order to optimally provide
stabilization for the expansion cone 2130 during axial movement of the
expansion cone 2130.
The upper sealing head 2130 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The upper sealing
head 2130 may be fabricated from any number of conventional commercially
available materials such as, for example, low alloy steel, carbon steel,
stainless
steel or other similar high strength materials. In a preferred embodiment, the
upper sealing head 2130 is fabricated from stainless steel in order to
optimally
provide high strength, corrosion resistance, and low friction surfaces. The
inner surface of the upper sealing head 2130 preferably includes one or more
annular sealing members 2210 for sealing the interface between the upper
sealing head 2130 and the inner sealing mandrel 2120. The sealing members
2210 may comprise any number of conventional commercially available annular
sealing members such as, for example, o-rings, polypak seals, or metal spring
energized seals. In a preferred embodiment, the sealing members 2210
comprise polypak seals available from Parker Seals in order to optimally
provide sealing for a long axial stroke.
In a preferred embodiment, the upper sealing head 2130 includes a
shoulder 2215 for supporting the upper sealing head 2130 on the lower sealing
head 2135.
The upper sealing head 2130 may be coupled to the outer sealing
mandrel 2140 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty threaded connection, welding, amorphous bonding or a
standard threaded connection. In a preferred embodiment, the upper sealing
head 2130 is removably coupled to the outer sealing mandrel 2140 by a
standard threaded connection. In a preferred embodiment, the mechanical
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coupling between the upper sealing head 2130 and the outer sealing mandrel
2140 includes one or more sealing members 2220 for fluidicly sealing the
interface between the upper sealing head 2130 and the outer sealing mandrel
2140. The sealing members 2220 may comprise any number of conventional
commercially available sealing members such as, for example, o-rings, polypak
seals, or metal spring energized seals. In a preferred embodiment, the sealing
members 2220 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for a long axial stroke.
The lower sealing head 2135 is coupled to the inner sealing mandrel 2120
and the load mandrel 2145. The lower sealing head 2135 is also movably
coupled to the inner surface of the outer sealing mandrel 2140. In this
manner,
the upper sealing head 2130, outer sealing mandrel 2140, and expansion cone
2150 reciprocate in the axial direction. The radial clearance between the
outer
surface of the lower sealing head 2135 and the inner surface of the outer
sealing
mandrel 2140 may range, for example, from about 0.0025 to 0.05 inches. In a
preferred embodiment, the radial clearance between the outer surface of the
lower sealing head 2135 and the inner surface of the outer sealing mandrel
2140
ranges from about 0.0025 to 0.05 inches in order to optimally provide minimal
radial clearance.
The lower sealing head 2135 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The lower sealing
head 2135 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel or other similar high strength
materials.
In a preferred embodiment, the lower sealing head 2135 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces. The outer surface of the lower sealing head 2135
preferably includes one or more annular sealing members 2225 for sealing the
interface between the lower sealing head 2135 and the outer sealing mandrel
2140. The sealing members 2225 may comprise any number of conventional
commercially available annular sealing members such as, for example, o-rings,
polypak seals or metal spring energized seals. In a preferred embodiment, the
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sealing members 2225 comprise polypak seals available from Parker Seals in
order to optimally provide sealing for a long axial stroke.
The lower sealing head 2135 may be coupled to the inner sealing mandrel
2120 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the lower sealing
head 2135 is removably coupled to the inner sealing mandrel 2120 by a
standard threaded connection. In a preferred embodiment, the mechanical
coupling between the lower sealing head 2135 and the inner sealing mandrel
2120 includes one or more sealing members 2230 for fluidicly sealing the
interface between the lower sealing head 2135 and the inner sealing mandrel
2120. The sealing members 2230 may comprise any number of conventional
commercially available sealing members such as, for example, o-rings, polypak
seals, or metal spring energized seals. In a preferred embodiment, the sealing
members 2230 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for a long axial stroke.
The lower sealing head 2135 may be coupled to the load mandrel 2145
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty threaded connection, welding, amorphous bonding, or a standard
threaded connection. In a preferred embodiment, the lower sealing head 2135
is removably coupled to the load mandrel 2145 by a standard threaded
connection. In a preferred embodiment, the mechanical coupling between the
lower sealing head 2135 and the load mandrel 2145 includes one or more
sealing members 2235 for fluidicly sealing the interface between the lower
sealing head 1930 and the load mandrel 2145. The sealing members 2235 may
comprise any number of conventional commercially available sealing members
such as, for example, o-rings, polypak seals, or metal spring energized seals.
In
a preferred embodiment, the sealing members 2235 comprise polypak seals
available from Parker Seals in order to optimally provide sealing for a long
axial
stroke.
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In a preferred embodiment, the lower sealing head 2135 includes a throat
passage 2240 fluidicly coupled between the fluid passages 2175 and 2180. The
throat passage 2240 is preferably of reduced size and is adapted to receive
and
engage with a plug 2245, or other similar device. In this manner, the fluid
passage 2175 is fluidicly isolated from the fluid passage 2180. In this
manner,
the pressure chamber 2250 is pressurized.
The outer sealing mandrel 2140 is coupled to the upper sealing head 2130
and the expansion cone 2150. The outer sealing mandrel 2140 is also movably
coupled to the inner surface of the casing 2155 and the outer surface of the
lower sealing head 2135. In this manner, the upper sealing head 2130, outer
sealing mandrel 2140, and the expansion cone 2150 reciprocate in the axial
direction. The radial clearance between the outer surface of the outer sealing
mandrel 2140 and the inner surface of the casing 2155 may range, for example,
from about 0.025 to 0.375 inches. In a preferred embodiment, the radial
clearance between the outer surface of the outer sealing mandrel 2140 and the
inner surface of the casing 2155 ranges from about 0.025 to 0.125 inches in
order to optimally provide stabilization for the expansion cone 2130 during
the
expansion process. The radial clearance between the inner surface of the outer
sealing mandrel 2140 and the outer surface of the lower sealing head 2135 may
range, for example, from about 0.005 to 0.125 inches. In a preferred
embodiment, the radial clearance between the inner surface of the outer
sealing
mandrel 2140 and the outer surface of the lower sealing head 2135 ranges from
about 0.005 to 0.010 inches in order to optimally provide minimal radial
clearance.
The outer sealing mandrel 2140 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The outer
sealing mandrel 2140 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel, or other similar high
strength materials. In a preferred embodiment, the outer sealing mandrel 2140
is fabricated from stainless steel in order to optimally provide high
strength,
corrosion resistance, and low friction surfaces.
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The outer sealing mandrel 2140 may be coupled to the upper sealing
head 2130 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty threaded connection, welding, amorphous bonding or a standard
threaded connection. In a preferred embodiment, the outer sealing mandrel
2140 is removably coupled to the upper sealing head 2130 by a standard
threaded connection. The outer sealing mandrel 2140 may be coupled to the
expansion cone 2150 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty threaded connection, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the outer sealing
mandrel 2140 is removably coupled to the expansion cone 2150 by a standard
threaded connection.
The upper sealing head 2130, the lower sealing head 2135, inner sealing
mandrel 2120, and the outer sealing mandrel 2140 together define a pressure
chamber 2250. The pressure chamber 2250 is fluidicly coupled to the passage
2175 via one or more passages 2255. During operation of the apparatus 2100,
the plug 2245 engages with the throat passage 2240 to fluidicly isolate the
fluid
passage 2175 from the fluid passage 2180. The pressure chamber 2250 is then
pressurized which in turn causes the upper sealing head 2130, outer sealing
mandrel 2140, and expansion cone 2150 to reciprocate in the axial direction.
The axial motion of the expansion cone 2150 in turn expands the casing 2155 in
the radial direction.
The load mandrel 2145 is coupled to the lower sealing head 2135. The
load mandrel 2145 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The load mandrel 2145 may
be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy
steel,
carbon steel, stainless steel or other similar high strength materials. In a
preferred embodiment, the load mandrel 2145 is fabricated from stainless steel
in order to optimally provide high strength, corrosion resistance, and low
friction bearing surfaces.
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The load mandrel 2145 may be coupled to the lower sealing head 2135
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty threaded connection, welding, amorphous bonding or a standard
threaded connection. In a preferred embodiment, the load mandrel 2145 is
removably coupled to the lower sealing head 2135 by a standard threaded
connection in order to optimally provide high strength and permit easy
replacement of the load mandrel 2145.
The load mandrel 2145 preferably includes a fluid passage 2180 that is
adapted to convey fluidic materials from the fluid passage 2180 to the region
outside of the apparatus 2100. In a preferred embodiment, the fluid passage
2180 is adapted to convey fluidic materials such as, for example, cement,
epoxy,
water, drilling mud, or lubricants at operating pressures and flow rates
ranging
from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The expansion cone 2150 is coupled to the outer sealing mandrel 2140.
The expansion cone 2150 is also movably coupled to the inner surface of the
casing 2155. In this manner, the upper sealing head 2130, outer sealing
mandrel 2140, and the expansion cone 2150 reciprocate in the axial direction.
The reciprocation of the expansion cone 2150 causes the casing 2155 to expand
in the radial direction.
The expansion cone 2150 preferably comprises an annular member
having substantially cylindrical inner and conical outer surfaces. The outside
radius of the outside conical surface may range, for example, from about 2 to
34
inches. In a preferred embodiment, the outside radius of the outside conical
surface ranges from about 3 to 28 inches in order to optimally provide cone
dimensions that are optimal for typical casings. The axial length of the
expansion cone 2150 may range, for example, from about 2 to 6 times the
largest outside diameter of the expansion cone 2150. In a preferred
embodiment, the axial length of the expansion cone 2150 ranges from about 3
to 5 times the largest outside diameter of the expansion cone 2150 in order to
optimally provide stability and centralization of the expansion cone 2150
during
the expansion process. In a particularly preferred embodiment, the maximum
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outside diameter of the expansion cone 2150 is between about 90 to 100 % of
the inside diameter of the existing wellbore that the casing 2155 will be
joined
with. In a preferred embodiment, the angle of attack of the expansion cone
2150 ranges from about 5 to 30 degrees in order to optimally balance friction
forces and radial expansion forces. The optimal expansion cone 2150 angle of
attack will vary as a function of the particular operating conditions of the
expansion operation.
The expansion cone 2150 may be fabricated from any number of
conventional commercially available materials such as, for example, machine
tool steel, nitride steel, titanium, tungsten carbide, ceramics, or other
similar
high strength materials. In a preferred embodiment, the expansion cone 2150
is fabricated from D2 machine tool steel in order to optimally provide high
strength and resistance to wear and galling. In a particularly preferred
embodiment, the outside surface of the expansion cone 2150 has a surface
hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
resistance to wear.
The expansion cone 2150 may be coupled to the outside sealing mandrel
2140 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, welding, amorphous bonding or a
standard threaded connection. In a preferred embodiment, the expansion cone
2150 is coupled to the outside sealing mandrel 2140 using a standard threaded
connection in order to optimally provide high strength and permit the
expansion cone 2150 to be easily replaced.
The casing 2155 is removably coupled to the slips 2125 and expansion
cone 2150. The casing 2155 preferably comprises a tubular member. The
casing 2155 may be fabricated from any number of conventional commercially
available materials such as, for example, slotted tubulars, oilfield country
tubular goods, low alloy steel, carbon steel, stainless steel or other similar
high
strength material. In a preferred embodiment, the casing 2155 is fabricated
from oilfield country tubular goods available from various foreign and
domestic
steel mills in order to optimally provide high strength.
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In a preferred embodiment, the upper end 2260 of the casing 2155
includes a thin wall section 2265 and an outer annular sealing member 2270.
In a preferred embodiment, the wall thickness of the thin wall section 2265 is
about 50 to 100 % of the regular wall thickness of the casing 2155. In this
manner, the upper end 2260 of the casing 2155 may be easily expanded and
deformed into intimate contact with the lower end of an existing section of
wellbore casing. In a preferred embodiment, the lower end of the existing
section of casing also includes a thin wall section. In this manner, the
radial
expansion of the thin walled section 2265 of casing 2155 into the thin walled
section of the existing wellbore casing results in a wellbore casing having a
substantially constant inside diameter.
The annular sealing member 2270 may be fabricated from any number of
conventional commercially available sealing materials such as, for example,
epoxy, rubber, metal or plastic. In a preferred embodiment, the annular
sealing
member 2270 is fabricated from StrataLock epoxy in order to optimally provide
compressibility and resistance to wear. The outside diameter of the annular
sealing member 2270 preferably ranges from about 70 to 95 % of the inside
diameter of the lower section of the wellbore casing that the casing 2155 is
joined to. In this manner, after expansion, the annular sealing member 2270
preferably provides a fluidic seal and also preferably provides sufficient
frictional force with the inside surface of the existing section of wellbore
casing
during the radial expansion of the casing 2155 to support the casing 2155.
In a preferred embodiment, the lower end 2275 of the casing 2155
includes a thin wall section 2280 and an outer annular sealing member 2285.
In a preferred embodiment, the wall thickness of the thin wall section 2280 is
about 50 to 100 % of the regular wall thickness of the casing 2155. In this
manner, the lower end 2275 of the casing 2155 may be easily expanded and
deformed. Furthermore, in this manner, an other section of casing may be
easily joined with the lower end 2275 of the casing 2155 using a radial
expansion process. In a preferred embodiment, the upper end of the other
section of casing also includes a thin wall section. In this manner, the
radial
expansion of the thin walled section of the upper end of the other casing into
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the thin walled section 2280 of the lower end of the casing 2155 results in a
wellbore casing having a substantially constant inside diameter.
The annular sealing member 2285 may be fabricated from any number of
conventional commercially available sealing materials such as, for example,
epoxy, rubber, metal or plastic. In a preferred embodiment, the annular
sealing
member 2285 is fabricated from StrataLock epoxy in order to optimally provide
compressibility and wear resistance. The outside diameter of the annular
sealing member 2285 preferably ranges from about 70 to 95 % of the inside
diameter of the lower section of the existing wellbore casing that the casing
2155 is joined to. In this manner, the annular sealing member 2285 preferably
provides a fluidic seal and also preferably provides sufficient frictional
force
with the inside wall of the wellbore during the radial expansion of the casing
2155 to support the casing 2155.
During operation, the apparatus 2100 is preferably positioned in a
wellbore with the upper end 2260 of the casing 2155 positioned in an
overlapping relationship with the lower end of an existing wellbore casing. In
a
particularly preferred embodiment, the thin wall section 2265 of the casing
2155 is positioned in opposing overlapping relation with the thin wall section
and outer annular sealing member of the lower end of the existing section of
wellbore casing. In this manner, the radial expansion of the casing 2155 will
compress the thin wall sections and annular compressible members of the upper
end 2260 of the casing 2155 and the lower end of the existing wellbore casing
into intimate contact. During the positioning of the apparatus 2100 in the
wellbore, the casing 2155 is supported by the expansion cone 2150.
After positioning of the apparatus 2100, a first fluidic material is then
pumped into the fluid passage 2160. The first fluidic material may comprise
any number of conventional commercially available materials such as, for
example, drilling mud, water, epoxy, or cement. In a preferred embodiment,
the first fluidic material comprises a hardenable fluidic sealing material
such as,
for example, cement or epoxy in order to provide a hardenable outer annular
body around the expanded casing 2155.
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The first fluidic material may be pumped into the fluid passage 2160 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi and 0 to 3,000 gallons/minute. In a preferred embodiment, the first
fluidic
material is pumped into the fluid passage 2160 at operating pressures and flow
rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order
to optimally provide operational efficiency.
The first fluidic material pumped into the fluid passage 2160 passes
through the fluid passages 2165, 2170, 2175, 2180 and then outside of the
apparatus 2100. The first fluidic material then fills the annular region
between
the outside of the apparatus 2100 and the interior walls of the wellbore.
The plug 2245 is then introduced into the fluid passage 2160. The plug
2245 lodges in the throat passage 2240 and fluidicly isolates and blocks off
the
fluid passage 2175. In a preferred embodiment, a couple of volumes of a non-
hardenable fluidic material are then pumped into the fluid passage 2160 in
order to remove any hardenable fluidic material contained within and to ensure
that none of the fluid passages are blocked.
A second fluidic material is then pumped into the fluid passage 2160.
The second fluidic material may comprise any number of conventional
commercially available materials such as, for example, drilling mud, water,
drilling gases, or lubricants. In a preferred embodiment, the second fluidic
material comprises a non-hardenable fluidic material such as, for example,
water, drilling mud or lubricant in order to optimally provide pressurization
of
the pressure chamber 2250 and minimize frictional forces.
The second fluidic material may be pumped into the fluid passage 2160 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi and 0 to 4,500 gallons/minute. In a preferred embodiment, the second
fluidic material is pumped into the fluid passage 2160 at operating pressures
and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute
in order to optimally provide operational efficiency.
The second fluidic material pumped into the fluid passage 2160 passes
through the fluid passages 2165, 2170, and 2175 into the pressure chambers
2195 of the slips 2125, and into the pressure chamber 2250. Continued
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pumping of the second fluidic material pressurizes the pressure chambers 2195
and 2250.
The pressurization of the pressure chambers 2195 causes the slip
members 2205 to expand in the radial direction and grip the interior surface
of
the casing 2155. The casing 2155 is then preferably maintained in a
substantially stationary position.
The pressurization of the.pressure chamber 2250 causes the upper
sealing head 2130, outer sealing mandrel 2140 and expansion cone 2150 to
move in an axial direction relative to the casing 2155. In this manner, the
expansion cone 2150 will cause the casing 2155 to expand in the radial
direction.
During the radial expansion process, the casing 2155 is prevented from
moving in an upward direction by the slips 2125. A length of the casing 2155
is
then expanded in the radial direction through the pressurization of the
pressure
chamber 2250. The length of the casing 2155 that is expanded during the
expansion process will be proportional to the stroke length of the upper
sealing
head 2130, outer sealing mandrel 2140, and expansion cone 2150.
Upon the completion of a stroke, the operating pressure of the second
fluidic material is reduced and the upper sealing head 2130, outer sealing
mandrel 2140, and expansion cone 2150 drop to their rest positions with the
casing 2155 supported by the expansion cone 2150. The position of the
drillpipe
2105 is preferably adjusted throughout the radial expansion process in order
to
maintain the overlapping relationship between the thin walled sections of the
lower end of the existing wellbore casing and the upper end of the casing
2155.
In a preferred embodiment, the stroking of the expansion cone 2150 is then
repeated, as necessary, until the thin walled section 2265 of the upper end
2260
of the casing 2155 is expanded into the thin walled section of the lower end
of
the existing wellbore casing. In this manner, a wellbore casing is formed
including two adjacent sections of casing having a substantially constant
inside
diameter. This process may then be repeated for the entirety of the wellbore
to
provide a wellbore casing thousands of feet in length having a substantially
constant inside diameter.
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In a preferred embodiment, during the final stroke of the expansion cone
2150, the slips 2125 are positioned as close as possible to the thin walled
section
2265 of the upper end of the casing 2155 in order minimize slippage between
the casing 2155 and the existing wellbore casing at the end of the radial
expansion process. Alternatively, or in addition, the outside diameter of the
annular sealing member 2270 is selected to ensure sufficient interference fit
with the inside diameter of the lower end of the existing casing to prevent
axial
displacement of the casing 2155 during the final stroke. Alternatively, or in
addition, the outside diameter of the annular sealing member 2285 is selected
to
provide an interference fit with the inside walls of the wellbore at an
earlier
point in the radial expansion process so as to prevent further axial
displacement
of the casing 2155. In this final alternative, the interference fit is
preferably
selected to permit expansion of the casing 2155 by pulling the expansion cone
2150 out of the wellbore, without having to pressurize the pressure chamber
2250.
During the radial expansion process, the pressurized areas of the
apparatus 2100 are limited to the fluid passages 2160, 2165, 2170, and 2175,
the
pressure chambers 2195 within the slips 2125, and the pressure chamber 2250.
No fluid pressure acts directly on the casing 2155. This permits the use of
operating pressures higher than the casing 2155 could normally withstand.
Once the casing 2155 has been completely expanded off of the expansion
cone 2150, remaining portions of the apparatus 2100 are removed from the
wellbore. In a preferred embodiment, the contact pressure between the
deformed thin wall sections and compressible annular members of the lower
end of the existing casing and the upper end 2260 of the casing 2155 ranges
from about 500 to 40,000 psi in order to optimally support the casing 2155
using the existing wellbore casing.
In this manner, the casing 2155 is radially expanded into contact with an
existing section of casing by pressurizing the interior fluid passages 2160,
2165,
2170, and 2175 and the pressure chamber 2250 of the apparatus 2100.
In a preferred embodiment, as required, the annular body of hardenable
fluidic material is then allowed to cure to form a rigid outer annular body
about
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the expanded casing 2155. In the case where the casing 2155 is slotted, the
cured fluidic material preferably permeates and envelops the expanded casing
2155. The resulting new section of wellbore casing includes the expanded
casing 2155 and the rigid outer annular body. The overlapping joint between
the pre-existing wellbore casing and the expanded casing 2155 includes the
deformed thin wall sections and the compressible outer annular bodies. The
inner diameter of the resulting combined wellbore casings is substantially
constant. In this manner, a mono-diameter wellbore casing is formed. This
process of expanding overlapping tubular members having thin wall end
portions with compressible annular bodies into contact can be repeated for the
entire length of a wellbore. In this manner, a mono-diameter wellbore casing
can be provided for thousands of feet in a subterranean formation.
In a preferred embodiment, as the expansion cone 2150 nears the upper
end of the casing 2155, the operating flow rate of the second fluidic material
is
reduced in order to minimize shock to the apparatus 2100. In an alternative
embodiment, the apparatus 2100 includes a shock absorber for absorbing the
shock created by the completion of the radial expansion of the casing 2155.
In a preferred embodiment, the reduced operating pressure of the second
fluidic material ranges from about 100 to 1,000 psi as the expansion cone 2130
nears the end of the casing 2155 in order to optimally provide reduced axial
movement and velocity of the expansion cone 2130. In a preferred embodiment,
the operating pressure of the second fluidic material is reduced during the
return stroke of the apparatus 2100 to the range of about 0 to 500 psi in
order
minimize the resistance to the movement of the expansion cone 2130 during the
return stroke. In a preferred embodiment, the stroke length of the apparatus
2100 ranges from about 10 to 45 feet in order to optimally provide equipment
lengths that can be handled by conventional oil well rigging equipment while
also minimizing the frequency at which the expansion cone 2130 must be
stopped so that the apparatus 2100 can be re-stroked.
In an alternative embodiment, at least a portion of the upper sealing
head 2130 includes an expansion cone for radially expanding the casing 2155
during operation of the apparatus 2100 in order to increase the surface area
of
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the casing 2155 acted upon during the radial expansion process. In this
manner, the operating pressures can be reduced.
Alternatively, the apparatus 2100 may be used to join a first section of
pipeline to an existing section of pipeline. Alternatively, the apparatus 2100
may be used to directly line the interior of a wellbore with a casing, without
the
use of an outer annular layer of a hardenable material. Alternatively, the
apparatus 2100 may be used to expand a tubular support member in a hole.
Referring now to Figures 17, 17a and 17b, another embodiment of an
apparatus 2300 for expanding a tubular member will be described. The
apparatus 2300 preferably includes a drillpipe 2305, an innerstring adapter
2310, a sealing sleeve 2315, a hydraulic slip body 2320, hydraulic slips 2325,
an
inner sealing mandrel 2330, an upper sealing head 2335, a lower sealing head
2340, a load mandrel 2345, an outer sealing mandrel 2350, an expansion cone
2355, a mechanical slip body 2360, mechanical slips 2365, drag blocks 2370,
casing 2375, fluid passages 2380, 2385, 2390, 2395, 2400, 2405, 2410, 2415,
and
2485, and mandrel launcher 2480.
The drillpipe 2305 is coupled to the innerstring adapter 2310. During
operation of the apparatus 2300, the drillpipe 2305 supports the apparatus
2300. The drillpipe 2305 preferably comprises a substantially hollow tubular
member or members. The drillpipe 2305 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other
similar high strength materials. In a preferred embodiment, the drillpipe 2305
is fabricated from coiled tubing in order to faciliate the placement of the
apparatus 2300 in non-vertical wellbores. The drillpipe 2305 may be coupled to
the innerstring adapter 2310 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty threaded connection, or a standard
threaded connection. In a preferred embodiment, the drillpipe 2305 is
removably coupled to the innerstring adapter 2310 by a drillpipe connection.
The drillpipe 2305 preferably includes a fluid passage 2380 that is
adapted to convey fluidic materials from a surface location into the fluid
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passage 2385. In a preferred embodiment, the fluid passage 2380 is adapted to
convey fluidic materials such as, for example, cement, water, epoxy, drilling
muds, or lubricants at operating pressures and flow rates ranging from about 0
to 9,000 psi and 0 to 5,000 gallons/minute in order to optimally provide
operational efficiency.
The innerstring adapter 2310 is coupled to the drill string 2305 and the
sealing sleeve 2315. The innerstring adapter 2310 preferably comprises a
substantially hollow tubular member or members. The innerstring adapter
2310 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel or other similar high strength
materials.
In a preferred embodiment, the innerstring adapter 2310 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces.
The innerstring adapter 2310 may be coupled to the drill string 2305
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty threaded connection, or a standard threaded connection. In a
preferred embodiment, the innerstring adapter 2310 is removably coupled to
the drill pipe 2305 by a drillpipe connection. The innerstring adapter 2310
may
be coupled to the sealing sleeve 2315 using any number of conventional
commercially available mechanical couplings such as, for example, a drillpipe
connection, oilfield country tubular goods specialty threaded connection, or a
standard threaded connection. In a preferred embodiment, the innerstring
adapter 2310 is removably coupled to the sealing sleeve 2315 by a standard
threaded connection.
The innerstring adapter 2310 preferably includes a fluid passage 2385
that is adapted to convey fluidic materials from the fluid passage 2380 into
the
fluid passage 2390. In a preferred embodiment, the fluid passage 2385 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud, drilling gases or lubricants at operating pressures and flow
rates
ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
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The sealing sleeve 2315 is coupled to the innerstring adapter 2310 and
the hydraulic slip body 2320. The sealing sleeve 2315 preferably comprises a
substantially hollow tubular member or members. The sealing sleeve 2315 may
be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy
steel,
carbon steel, stainless steel or other similar high strength materials. In a
preferred embodiment, the sealing sleeve 2315 is fabricated from stainless
steel
in order to optimally provide high strength, corrosion resistance, and low-
friction surfaces.
The sealing sleeve 2315 may be coupled to the innerstring adapter 2310
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connections, oilfield country tubular goods
specialty threaded connections, or a standard threaded connection. In a
preferred embodiment, the sealing sleeve 2315 is removably coupled to the
innerstring adapter 2310 by a standard threaded connection. The sealing sleeve
2315 may be coupled to the hydraulic slip body 2320 using any number of
conventional commercially available mechanical couplings such as, for example,
drillpipe connection, oilfield country tubular goods specialty threaded
connection, or a standard threaded connection. In a preferred embodiment, the
sealing sleeve 2315 is removably coupled to the hydraulic slip body 2320 by a
standard threaded connection.
The sealing sleeve 2315 preferably includes a fluid passage 2390 that is
adapted to convey fluidic materials from the fluid passage 2385 into the fluid
passage 2395. In a preferred embodiment, the fluid passage 2315 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud or lubricants at operating pressures and flow rates ranging from about 0
to
9,000 psi and 0 to 3,000 gallons/minute.
The hydraulic slip body 2320 is coupled to the sealing sleeve 2315, the
hydraulic slips 2325, and the inner sealing mandrel 2330. The hydraulic slip
body 2320 preferably comprises a substantially hollow tubular member or
members. The hydraulic slip body 2320 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
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country tubular goods, low alloy steel, carbon steel, stainless steel or other
high
strength material. In a preferred embodiment, the hydraulic slip body 2320 is
fabricated from carbon steel in order to optimally provide high strength at
low
cost.
The hydraulic slip body 2320 may be coupled to the sealing sleeve 2315
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty threaded connection, or a standard threaded connection. In a
preferred embodiment, the hydraulic slip body 2320 is removably coupled to the
sealing sleeve 2315 by a standard threaded connection. The hydraulic slip body
2320 may be coupled to the slips 2325 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty threaded connection,
welding, amorphous bonding or a standard threaded connection. In a preferred
embodiment, the hydraulic slip body 2320 is removably coupled to the slips
2325 by a standard threaded connection. The hydraulic slip body 2320 may be
coupled to the inner sealing mandrel 2330 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty threaded connection,
welding, amorphous bonding or a standard threaded connection. In a preferred
embodiment, the hydraulic slip body 2320 is removably coupled to the inner
sealing mandrel 2330 by a standard threaded connection.
The hydraulic slips body 2320 preferably includes a fluid passage 2395
that is adapted to convey fluidic materials from the fluid passage 2390 into
the
fluid passage 2405. In a preferred embodiment, the fluid passage 2395 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The hydraulic slips body 2320 preferably includes fluid passage 2400 that
are adapted to convey fluidic materials from the fluid passage 2395 into the
pressure chambers 2420 of the hydraulic slips 2325. In this manner, the slips
2325 are activated upon the pressurization of the fluid passage 2395 into
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contact with the inside surface of the casing 2375. In a preferred embodiment,
the fluid passages 2400 are adapted to convey fluidic materials such as, for
example, water, drilling mud or lubricants at operating pressures and flow
rates
ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The slips 2325 are coupled to the outside surface of the hydraulic slip
body 2320. During operation of the apparatus 2300, the slips 2325 are
activated
upon the pressurization of the fluid passage 2395 into contact with the inside
surface of the casing 2375. In this manner, the slips 2325 maintain the casing
2375 in a substantially stationary position.
The slips 2325 preferably include the fluid passages 2400, the pressure
chambers 2420, spring bias 2425, and slip members 2430. The slips 2325 may
comprise any number of conventional commercially available hydraulic slips
such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L
retrievable bridge plug with hydraulic slips. In a preferred embodiment, the
slips 2325 comprise RTTS packer tungsten carbide hydraulic slips available
from Halliburton Energy Services in order to optimally provide resistance to
axial movement of the casing 2375 during the radial expansion process.
The inner sealing mandrel 2330 is coupled to the hydraulic slip body
2320 and the lower sealing head 2340. The inner sealing mandrel 2330
preferably comprises a substantially hollow tubular member or members. The
inner sealing mandrel 2330 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the inner sealing mandrel 2330 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The inner sealing mandrel 2330 may be coupled to the hydraulic slip
body 2320 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty threaded connection, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the inner sealing
mandrel 2330 is removably coupled to the hydraulic slip body 2320 by a
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standard threaded connection. The inner sealing mandrel 2330 may be coupled
to the lower sealing head 2340 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty threaded connection, welding,
amorphous bonding, or a standard threaded connection. In a preferred
embodiment, the inner sealing mandrel 2330 is removably coupled to the lower
sealing head 2340 by a standard threaded connection.
The inner sealing mandrel 2330 preferably includes a fluid passage 2405
that is adapted to convey fluidic materials from the fluid passage 2395 into
the
fluid passage 2415. In a preferred embodiment, the fluid passage 2405 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud, or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The upper sealing head 2335 is coupled to the outer sealing mandrel 2345
and expansion cone 2355. The upper sealing head 2335 is also movably coupled
to the outer surface of the inner sealing mandrel 2330 and the inner surface
of
the casing 2375. In this manner, the upper sealing head 2335 reciprocates in
the axial direction. The radial clearance between the inner cylindrical
surface
of the upper sealing head 2335 and the outer surface of the inner sealing
mandrel 2330 may range, for example, from about 0.0025 to 0.05 inches. In a
preferred embodiment, the radial clearance between the inner cylindrical
surface of the upper sealing head 2335 and the outer surface of the inner
sealing mandrel 2330 ranges from about 0.005 to 0.01 inches in order to
optimally provide minimal clearance. The radial clearance between the outer
cylindrical surface of the upper sealing head 2335 and the inner surface of
the
casing 2375 may range, for example, from about 0.025 to 0.375 inches. In a
preferred embodiment, the radial clearance between the outer cylindrical
surface of the upper sealing head 2335 and the inner surface of the casing
2375
ranges from about 0.025 to 0.125 inches in order to optimally provide
stabilization for the expansion cone 2355 during the expansion process.
The upper sealing head 2335 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The upper sealing
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head 2335 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel or other similar high strength
materials.
In a preferred embodiment, the upper sealing head 2335 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces. The inner surface of the upper sealing head 2335
preferably includes one or more annular sealing members 2435 for sealing the
interface between the upper sealing head 2335 and the inner sealing mandrel
2330. The sealing members 2435 may comprise any number of conventional
commercially available annular sealing members such as, for example, o-rings,
polypak seals or metal spring energized seals. In a preferred embodiment, the
sealing members 2435 comprise polypak seals available from Parker Seals in
order to optimally provide sealing for a long axial stroke.
In a preferred embodiment, the upper sealing head 2335 includes a
shoulder 2440 for supporting the upper sealing head on the lower sealing head
1930.
The upper sealing head 2335 may be coupled to the outer sealing
mandrel 2350 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty threaded connection, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the upper sealing
head 2335 is removably coupled to the outer sealing mandrel 2350 by a
standard threaded connection. In a preferred embodiment, the mechanical
coupling between the upper sealing head 2335 and the outer sealing mandrel
2350 includes one or more sealing members 2445 for fluidicly sealing the
interface between the upper sealing head 2335 and the outer sealing mandrel
2350. The sealing members 2445 may comprise any number of conventional
commercially available sealing members such as, for example, o-rings, polypak
seals or metal spring energized seals. In a preferred embodiment, the sealing
members 2445 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for long axial strokes.
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The lower sealing head 2340 is coupled to the inner sealing mandrel 2330
and the load mandrel 2345. The lower sealing head 2340 is also movably
coupled to the inner surface of the outer sealing mandrel 2350. In this
manner,
the upper sealing head 2335 and outer sealing mandrel 2350 reciprocate in the
axial direction. The radial clearance between the outer surface of the lower
sealing head 2340 and the inner surface of the outer sealing mandrel 2350 may
range, for example, from about 0.0025 to 0.05 inches. In a preferred
embodiment, the radial clearance between the outer surface of the lower
sealing
head 2340 and the inner surface of the outer sealing mandrel 2350 ranges from
about 0.005 to 0.010 inches in order to optimally provide minimal radial
clearance.
The lower sealing head 2340 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The lower sealing
head 2340 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield tubular members, low alloy
steel, carbon steel, stainless steel or other similar high strength materials.
In a
preferred embodiment, the lower sealing head 2340 is fabricated from stainless
steel in order to optimally provide high strength, corrosion resistance, and
low
friction surfaces. The outer surface of the lower sealing head 2340 preferably
includes one or more annular sealing members 2450 for sealing the interface
between the lower sealing head 2340 and the outer sealing mandrel 2350. The
sealing members 2450 may comprise any number of conventional commercially
available annular sealing members such as, for example, o-rings, polypak seals
or metal spring energized seals. In a preferred embodiment, the sealing
members 2450 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for a long axial stroke.
The lower sealing head 2340 may be coupled to the inner sealing mandrel
2330 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
specialty threaded connection, welding, amorphous bonding, or standard
threaded connection. In a preferred embodiment, the lower sealing head 2340
is removably coupled to the inner sealing mandrel 2330 by a standard threaded
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connection. In a preferred embodiment, the mechanical coupling between the
lower sealing head 2340 and the inner sealing mandrel 2330 includes one or
more sealing members 2455 for fluidicly sealing the interface between the
lower
sealing head 2340 and the inner sealing mandrel 2330. The sealing members
2455 may comprise any number of conventional commercially available sealing
members such as, for example, o-rings, polypak or metal spring energized
seals.
In a preferred embodiment, the sealing members 2455 comprise polypak seals
available from Parker Seals in order to optimally provide sealing for a long
axial
stroke length.
The lower sealing head 2340 may be coupled to the load mandrel 2345
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty threaded connection, welding, amorphous bonding or a standard
threaded connection. In a preferred embodiment, the lower sealing head 2340
is removably coupled to the load mandrel 2345 by a standard threaded
connection. In a preferred embodiment, the mechanical coupling between the
lower sealing head 2340 and the load mandrel 2345 includes one or more
sealing members 2460 for fluidicly sealing the interface between the lower
sealing head 2340 and the load mandrel 2345. The sealing members 2460 may
comprise any number of conventional commercially available sealing members
such as, for example, o-rings, polypak seals or metal spring energized seals.
In
a preferred embodiment, the sealing members 2460 comprise polypak seals
available from Parker Seals in order to optimally provide sealing for a long
axial
stroke length.
In a preferred embodiment, the lower sealing head 2340 includes a throat
passage 2465 fluidicly coupled between the fluid passages 2405 and 2415. The
throat passage 2465 is preferably of reduced size and is adapted to receive
and
engage with a plug 2470, or other similar device. In this manner, the fluid
passage 2405 is fluidicly isolated from the fluid passage 2415. In this
manner,
the pressure chamber 2475 is pressurized.
The outer sealing mandrel 2350 is coupled to the upper sealing head 2335
and the expansion cone 2355. The outer sealing mandrel 2350 is also movably
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coupled to the inner surface of the casing 2375 and the outer surface of the
lower sealing head 2340. In this manner, the upper sealing head 2335, outer
sealing mandrel 2350, and the expansion cone 2355 reciprocate in the axial
direction. The radial clearance between the outer surface of the outer sealing
mandrel 2350 and the inner surface of the casing 2375 may range, for example,
from about 0.025 to 0.375 inches. In a preferred embodiment, the radial
clearance between the outer surface of the outer sealing mandrel 2350 and the
inner surface of the casing 2375 ranges from about 0.025 to 0.125 inches in
order to optimally provide stabilization for the expansion cone 2355 during
the
expansion process. The radial clearance between the inner surface of the outer
sealing mandrel 2350 and the outer surface of the lower sealing head 2340 may
range, for example, from about 0.0025 to 0.375 inches. In a preferred
embodiment, the radial clearance between the inner surface of the outer
sealing
mandrel 2350 and the outer surface of the lower sealing head 2340 ranges from
about 0.005 to 0.010 inches in order to optimally provide minimal clearance.
The outer sealing mandrel 2350 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The outer
sealing mandrel 2350 may be fabricated from any number of conventional
commercially available materials such as, for example, low alloy steel, carbon
steel, stainless steel or other similar high strength materials. In a
preferred
embodiment, the outer sealing mandrel 2350 is fabricated from stainless steel
in order to optimally provide high strength, corrosion resistance, and low
friction surfaces.
The outer sealing mandrel 2350 may be coupled to the upper sealing
head 2335 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connections, oilfield country
tubular
goods specialty threaded connections, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the outer sealing
mandrel 2350 is removably coupled to the upper sealing head 2335 by a
standard threaded connection. The outer sealing mandrel 2350 may be coupled
to the expansion cone 2355 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
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oilfield country tubular goods specialty threaded connection, welding,
amorphous bonding, or a standard threaded connection. In a preferred
embodiment, the outer sealing mandrel 2350 is removably coupled to the
expansion cone 2355 by a standard threaded connection.
The upper sealing head 2335, the lower sealing head 2340, the inner
sealing mandrel 2330, and the outer sealing mandrel 2350 together define a
pressure chamber 2475. The pressure chamber 2475 is fluidicly coupled to the
passage 2405 via one or more passages 2410. During operation of the apparatus
2300, the plug 2470 engages with the throat passage 2465 to fluidicly isolate
the
fluid passage 2415 from the fluid passage 2405. The pressure chamber 2475 is
then pressurized which in turn causes the upper sealing head 2335, outer
sealing mandrel 2350, and expansion cone 2355 to reciprocate in the axial
direction. The axial motion of the expansion cone 2355 in turn expands the
casing 2375 in the radial direction.
The load mandrel 2345 is coupled to the lower sealing head 2340 and the
mechanical slip body 2360. The load mandrel 2345 preferably comprises an
annular member having substantially cylindrical inner and outer surfaces. The
load mandrel 2345 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the load mandrel 2345 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces.
The load mandrel 2345 may be coupled to the lower sealing head 2340
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty threaded connection, welding, amorphous bonding or a standard
threaded connection. In a preferred embodiment, the load mandrel 2345 is
removably coupled to the lower sealing head 2340 by a standard threaded
connection. The load mandrel 2345 may be coupled to the mechanical slip body
2360 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
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goods specialty threaded connection, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the load mandrel
2345 is removably coupled to the mechanical slip body 2360 by a standard
threaded connection.
The load mandrel 2345 preferably includes a fluid passage 2415 that is
adapted to convey fluidic materials from the fluid passage 2405 to the region
outside of the apparatus 2300. In a preferred embodiment, the fluid passage
2415 is adapted to convey fluidic materials such as, for example, cement,
epoxy,
water, drilling mud or lubricants at operating pressures and flow rates
ranging
from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The expansion cone 2355 is coupled to the outer sealing mandrel 2350.
The expansion cone 2355 is also movably coupled to the inner surface of the
casing 2375. In this manner, the upper sealing head 2335, outer sealing
mandrel 2350, and the expansion cone 2355 reciprocate in the axial direction.
The reciprocation of the expansion cone 2355 causes the casing 2375 to expand
in the radial direction.
The expansion cone 2355 preferably comprises an annular member
having substantially cylindrical inner and conical outer surfaces. The outside
radius of the outside conical surface may range, for example, from about 2 to
34
inches. In a preferred embodiment, the outside radius of the outside conical
surface ranges from about 3 to 28 inches in order to optimally provide radial
expansion of the typical casings. The axial length of the expansion cone 2355
may range, for example, from about 2 to 8 times the largest outside diameter
of
the expansion cone 2355. In a preferred embodiment, the axial length of the
expansion cone 2355 ranges from about 3 to 5 times the largest outside
diameter of the expansion cone 2355 in order to optimally provide stability
and
centralization of the expansion cone 2355 during the expansion process. In a
preferred embodiment, the angle of attack of the expansion cone 2355 ranges
from about 5 to 30 degrees in order to optimally frictional forces with radial
expansion forces. The optimum angle of attack of the expansion cone 2355 will
vary as a function of the operating parameters of the particular expansion
operation.
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The expansion cone 2355 may be fabricated from any number of
conventional commercially available materials such as, for example, machine
tool steel, nitride steel, titanium, tungsten carbide, ceramics or other
similar
high strength materials. In a preferred embodiment, the expansion cone 2355
is fabricated from D2 machine tool steel in order to optimally provide high
strength, abrasion resistance, and galling resistance. In a particularly
preferred
embodiment, the outside surface of the expansion cone 2355 has a surface
hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
high strength, abrasion resistance, resistance to galling.
The expansion cone 2355 may be coupled to the outside sealing mandrel
2350 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty threaded connection, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the expansion
cone 2355 is coupled to the outside sealing mandrel 2350 using a standard
threaded connection in order to optimally provide high strength and permit the
expansion cone 2355 to be easily replaced.
The mandrel launcher 2480 is coupled to the casing 2375. The mandrel
launcher 2480 comprises a tubular section of casing having a reduced wall
thickness compared to the casing 2375. In a preferred embodiment, the wall
thickness of the mandrel launcher 2480 is about 50 to 100 % of the wall
thickness of the casing 2375. In this manner, the initiation of the radial
expansion of the casing 2375 is facilitated, and the placement of the
apparatus
2300 into a wellbore casing and wellbore is facilitated.
The mandrel launcher 2480 may be coupled to the casing 2375 using any
number of conventional mechanical couplings. The mandrel launcher 2480 may
have a wall thickness ranging, for example, from about 0.15 to 1.5 inches. In
a
preferred embodiment, the wall thickness of the mandrel launcher 2480 ranges
from about 0.25 to 0.75 inches in order to optimally provide high strength in
a
minimal profile. The mandrel launcher 2480 may be fabricated from any
number of conventional commercially available materials such as, for example,
oilfield tubular goods, low alloy steel, carbon steel, stainless steel or
other
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similar high strength materials. In a preferred embodiment, the mandrel
launcher 2480 is fabricated from oilfield tubular goods having a higher
strength
than that of the casing 2375 but with a smaller wall thickness than the casing
2375 in order to optimally provide a thin walled container having
approximately
the same burst strength as that of the casing 2375.
The mechanical slip body 2460 is coupled to the load mandrel 2345, the
mechanical slips 2365, and the drag blocks 2370. The mechanical slip body
2460 preferably comprises a tubular member having an inner passage 2485
fluidicly coupled to the passage 2415. In this manner, fluidic materials may
be
conveyed from the passage 2484 to a region outside of the apparatus 2300.
The mechanical slip body 2360 may be coupled to the load mandrel 2345
using any number of conventional mechanical couplings. In a preferred
embodiment, the mechanical slip body 2360 is removably coupled to the load
mandrel 2345 using threads and sliding steel retaining rings in order to
optimally provide a high strength attachment. The mechanical slip body 2360
may be coupled to the mechanical slips 2365 using any number of conventional
mechanical couplings. In a preferred embodiment, the mechanical slip body
2360 is removably coupled to the mechanical slips 2365 using threads and
sliding steel retaining rings in order to optimally provide a high strength
attachment. The mechanical slip body 2360 may be coupled to the drag blocks
2370 using any number of conventional mechanical couplings. In a preferred
embodiment, the mechanical slip body 2360 is removably coupled to the drag
blocks 2365 using threads and sliding steel retaining rings in order to
optimally
provide a high strength attachment.
The mechanical slips 2365 are coupled to the outside surface of the
mechanical slip body 2360. During operation of the apparatus 2300, the
mechanical slips 2365 prevent upward movement of the casing 2375 and
mandrel launcher 2480. In this manner, during the axial reciprocation of the
expansion cone 2355, the casing 2375 and mandrel launcher 2480 are
maintained in a substantially stationary position. In this manner, the mandrel
launcher 2480 and casing 2375 are expanded in the radial direction by the
axial
movement of the expansion cone 2355.
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The mechanical slips 2365 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer
tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or
Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In a
preferred embodiment, the mechanical slips 2365 comprise RTTS packer
tungsten carbide mechanical slips available from Halliburton Energy Services
in order to optimally provide resistance to axial movement of the casing 2375
during the expansion process.
The drag blocks 2370 are coupled to the outside surface of the mechanical
slip body 2360. During operation of the apparatus 2300, the drag blocks 2370
prevent upward movement of the casing 2375 and mandrel launcher 2480. In
this manner, during the axial reciprocation of the expansion cone 2355, the
casing 2375 and mandrel launcher 2480 are maintained in a substantially
stationary position. In this manner, the mandrel launcher 2480 and casing
2375 are expanded in the radial direction by the axial movement of the
expansion cone 2355.
The drag blocks 2370 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer
mechanical drag blocks or Model 3L retrievable bridge plug drag blocks. In a
preferred embodiment, the drag blocks 2370 comprise RTTS packer mechanical
drag blocks available from Halliburton Energy Services in order to optimally
provide resistance to axial movement of the casing 2375 during the expansion
process.
The casing 2375 is coupled to the mandrel launcher 2480. The casing
2375 is further removably coupled to the mechanical slips 2365 and drag blocks
2370. The casing 2375 preferably comprises a tubular member. The casing
2375 may be fabricated from any number of conventional commercially
available materials such as, for example, slotted tubulars, oil country
tubular
goods, carbon steel, low alloy steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the casing 2375 is fabricated from
oilfield country tubular goods available from various foreign and domestic
steel
mills in order to optimally provide high strength. In a preferred embodiment,
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the upper end of the casing 2375 includes one or more sealing members
positioned about the exterior of the casing 2375.
During operation, the apparatus 2300 is positioned in a wellbore with the
upper end of the casing 2375 positioned in an overlapping relationship within
an existing wellbore casing. In order minimize surge pressures within the
borehole during placement of the apparatus 2300, the fluid passage 2380 is
preferably provided with one or more pressure relief passages. During the
placement of the apparatus 2300 in the wellbore, the casing 2375 is supported
by the expansion cone 2355.
After positioning of the apparatus 2300 within the bore hole in an
overlapping relationship with an existing section of wellbore casing, a first
fluidic material is pumped into the fluid passage 2380 from a surface
location.
The first fluidic material is conveyed from the fluid passage 2380 to the
fluid
passages 2385, 2390, 2395, 2405, 2415, and 2485. The first fluidic material
will
then exit the apparatus 2300 and fill the annular region between the outside
of
the apparatus 2300 and the interior walls of the bore hole.
The first fluidic material may comprise any number of conventional
commercially available materials such as, for example, epoxy, drilling mud,
slag
mix, cement, or water. In a preferred embodiment, the first fluidic material
comprises a hardenable fluidic sealing material such as, for example, slag
mix,
epoxy, or cement. In this manner, a wellbore casing having an outer annular
layer of a hardenable material may be formed.
The first fluidic material may be pumped into the apparatus 2300 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi, and 0 to 3,000 gallons/minute. In a preferred embodiment, the first
fluidic
material is pumped into the apparatus 2300 at operating pressures and flow
rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order
to optimally provide operational efficiency.
At a predetermined point in the injection of the first fluidic material such
as, for example, after the annular region outside of the apparatus 2300 has
been
filled to a predetermined level, a plug 2470, dart, or other similar device is
introduced into the first fluidic material. The plug 2470 lodges in the throat
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passage 2465 thereby fluidicly isolating the fluid passage 2405 from the fluid
passage 2415.
After placement of the plug 2470 in the throat passage 2465, a second
fluidic material is pumped into the fluid passage 2380 in order to pressurize
the
pressure chamber 2475. The second fluidic material may comprise any number
of conventional commercially available materials such as, for example, water,
drilling gases, drilling mud or lubricants. In a preferred embodiment, the
second fluidic material comprises a non-hardenable fluidic material such as,
for
example, water, drilling mud or lubricant.
The second fluidic material may be pumped into the apparatus 2300 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi and 0 to 4,500 gallons/minute. In a preferred embodiment, the second
fluidic material is pumped into the apparatus 2300 at operating pressures and
flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in
order to optimally provide operational efficiency.
The pressurization of the pressure chamber 2475 causes the upper
sealing head 2335, outer sealing mandrel 2350, and expansion cone 2355 to
move in an axial direction. The pressurization of the pressure chamber 2475
also causes the hydraulic slips 2325 to expand in the radial direction and
hold
the casing 2375 in a substantially stationary position. Furthermore, as the
expansion cone 2355 moves in the axial direction, the expansion cone 2355
pulls
the mandrel launcher 2480 and drag blocks 2370 along, which sets the
mechanical slips 2365 and stops further axial movement of the mandrel
launcher 2480 and casing 2375. In this manner, the axial movement of the
expansion cone 2355 radially expands the mandrel launcher 2480 and casing
2375.
Once the upper sealing head 2335, outer sealing mandrel 2350, and
expansion cone 2355 complete an axial stroke, the operating pressure of the
second fluidic material is reduced. The reduction in the operating pressure of
the second fluidic material releases the hydraulic slips 2325. The drill
string
2305 is then raised. This causes the inner sealing mandrel 2330, lower sealing
head 2340, load mandrel 2345, and mechanical slip body 2360 to move upward.
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This unsets the mechanical slips 2365 and permits the mechanical slips 2365
and drag blocks 2370 to be moved within the mandrel launcher 2480 and casing
2375. When the lower sealing head 2340 contacts the upper sealing head 2335,
the second fluidic material is again pressurized and the radial expansion
process
continues. In this manner, the mandrel launcher 2480 and casing 2375 are
radial expanded through repeated axial strokes of the upper sealing head 2335,
outer sealing mandrel 2350 and expansion cone 2355. Throughput the radial
expansion process, the upper end of the casing 2375 is preferably maintained
in
an overlapping relation with an existing section of wellbore casing.
At the end of the radial expansion process, the upper end of the casing
2375 is expanded into intimate contact with the inside surface of the lower
end
of the existing wellbore casing. In a preferred embodiment, the sealing
members provided at the upper end of the casing 2375 provide a fluidic seal
between the outside surface of the upper end of the casing 2375 and the inside
surface of the lower end of the existing wellbore casing. In a preferred
embodiment, the contact pressure between the casing 2375 and the existing
section of wellbore casing ranges from about 400 to 10,000 psi in order to
optimally provide contact pressure, activate the sealing members, and
withstand typical tensile and compressive loading conditions.
In a preferred embodiment, as the expansion cone 2355 nears the upper
end of the casing 23?5, the operating pressure of the second fluidic material
is
reduced in order to minimize shock to the apparatus 2300. In an alternative
embodiment, the apparatus 2300 includes a shock absorber for absorbing the
shock created by the completion of the radial expansion of the casing 2375.
In a preferred embodiment, the reduced operating pressure of the second
fluidic material ranges from about 100 to 1,000 psi as the expansion cone 2355
nears the end of the casing 2375 in order to optimally provide reduced axial
movement and velocity of the expansion cone 2355. In a preferred embodiment,
the operating pressure of the second fluidic material is reduced during the
return stroke of the apparatus 2300 to the range of about 0 to 500 psi in
order
minimize the resistance to the movement of the expansion cone 2355 during the
return stroke. In a preferred embodiment, the stroke length of the apparatus
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2300 ranges from about 10 to 45 feet in order to optimally provide equipment
that can be handled by typical oil well rigging equipment and minimize the
frequency at which the expansion cone 2355 must be stopped to permit the
apparatus 2300 to be re-stroked.
In an alternative embodiment, at least a portion of the upper sealing
head 2335 includes an expansion cone for radially expanding the mandrel
launcher 2480 and casing 2375 during operation of the apparatus 2300 in order
to increase the surface area of the casing 2375 acted upon during the radial
expansion process. In this manner, the operating pressures can be reduced.
In an alternative embodiment, mechanical slips 2365 are positioned in an
axial location between the sealing sleeve 2315 and the inner sealing mandrel
2330 in order to optimally the construction and operation of the apparatus
2300.
Upon the complete radial expansion of the casing 2375, if applicable, the
first fluidic material is permitted to cure within the annular region between
the
outside of the expanded casing 2375 and the interior walls of the wellbore. In
the case where the casing 2375 is slotted, the cured fluidic material
preferably
permeates and envelops the expanded casing 2375. In this manner, a new
section of wellbore casing is formed within a wellbore. Alternatively, the
apparatus 2300 may be used to join a first section of pipeline to an existing
section of pipeline. Alternatively, the apparatus 2300 may be used to directly
line the interior of a wellbore with a casing, without the use of an outer
annular
layer of a hardenable material. Alternatively, the apparatus 2300 may be used
to expand a tubular support member in a hole.
During the radial expansion process, the pressurized areas of the
apparatus 2300 are limited to the fluid passages 2380, 2385, 2390, 2395, 2400,
2405, and 2410, and the pressure chamber 2475. No fluid pressure acts directly
on the mandrel launcher 2480 and casing 2375. This permits the use of
operating pressures higher than the mandrel launcher 2480 and casing 2375
could normally withstand.
Referring now to Figure 18, a preferred embodiment of an apparatus
2500 for forming a mono-diameter wellbore casing will be described. The
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apparatus 2500 preferably includes a drillpipe 2505, an innerstring adapter
2510, a sealing sleeve 2515, a hydraulic slip body 2520, hydraulic slips 2525,
an
inner sealing mandrel 2530, upper sealing head 2535, lower sealing head 2540,
outer sealing mandrel 2545, load mandrel 2550, expansion cone 2555, casing
2560, and fluid passages 2565, 2570, 2575, 2580, 2585, 2590, 2595, and 2600.
The drillpipe 2505 is coupled to the innerstring adapter 2510. During
operation of the apparatus 2500, the drillpipe 2505 supports the apparatus
2500. The drillpipe 2505 preferably comprises a substantially hollow tubular
member or members. The drillpipe 2505 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other
similar high strength materials. In a preferred embodiment, the drillpipe 2505
is fabricated from coiled tubing in order to faciliate the placement of the
apparatus 2500 in non-vertical wellbores. The drillpipe 2505 may be coupled to
the innerstring adapter 2510 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty threaded connection, or a standard
threaded connection. In a preferred embodiment, the drillpipe 2505 is
removably coupled to the innerstring adapter 2510 by a drillpipe connection. a
drillpipe connection provides the advantages of high strength and easy
disassembly.
The drillpipe 2505 preferably includes a fluid passage 2565 that is
adapted to convey fluidic materials from a surface location into the fluid
passage 2570. In a preferred embodiment, the fluid passage 2565 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud, or lubricants at operating pressures and flow rates ranging from about 0
to 9,000 psi and 0 to 3,000 gallons/minute.
The innerstring adapter 2510 is coupled to the drill string 2505 and the
sealing sleeve 2515. The innerstring adapter 2510 preferably comprises a
substantially hollow tubular member or members. The innerstring adapter
2510 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
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alloy steel, carbon steel, stainless steel or other similar high strength
materials.
In a preferred embodiment, the innerstring adapter 2510 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces.
The innerstring adapter 2510 may be coupled to the drill string 2505
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, or a standard threaded connection. In a
preferred embodiment, the innerstring adapter 2510 is removably coupled to
the drill pipe 2505 by a drillpipe connection. The innerstring adapter 2510
may
be coupled to the sealing sleeve 2515 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty type threaded connection,
ratchet-latch type threaded connection or a standard threaded connection. In a
preferred embodiment, the innerstring adapter 2510 is removably coupled to
the sealing sleeve 2515 by a standard threaded connection.
The innerstring adapter 2510 preferably includes a fluid passage 2570
that is adapted to convey fluidic materials from the fluid passage 2565 into
the
fluid passage 2575. In a preferred embodiment, the fluid passage 2570 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The sealing sleeve 2515 is coupled to the innerstring adapter 2510 and
the hydraulic slip body 2520. The sealing sleeve 2515 preferably comprises a
substantially hollow tubular member or members. The sealing sleeve 2515 may
be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy
steel,
carbon steel, stainless steel or other similar high strength materials. In a
preferred embodiment, the sealing sleeve 2515 is fabricated from stainless
steel
in order to optimally provide high strength, corrosion resistance, and low-
friction surfaces.
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The sealing sleeve 2515 may be coupled to the innerstring adapter 2510
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connections, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type threaded connection, or
a
standard threaded connection. In a preferred embodiment, the sealing sleeve
2515 is removably coupled to the innerstring adapter 2510 by a standard
threaded connection. The sealing sleeve 2515 may be coupled to the hydraulic
slip body 2520 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection, or a standard threaded connection. In a preferred embodiment, the
sealing sleeve 2515 is removably coupled to the hydraulic slip body 2520 by a
standard threaded connection.
The sealing sleeve 2515 preferably includes a fluid passage 2575 that is
adapted to convey fluidic materials from the fluid passage 2570 into the fluid
passage 2580. In a preferred embodiment, the fluid passage 2575 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud or lubricants at operating pressures and flow rates ranging from about 0
to
9,000 psi and 0 to 3,000 gallons/minute.
The hydraulic slip body 2520 is coupled to the sealing sleeve 2515, the
hydraulic slips 2525, and the inner sealing mandrel 2530. The hydraulic slip
body 2520 preferably comprises a substantially hollow tubular member or
members. The hydraulic slip body 2520 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other
similar high strength materials. In a preferred embodiment, the hydraulic slip
body 2520 is fabricated from carbon steel in order to optimally provide high
strength.
The hydraulic slip body 2520 may be coupled to the sealing sleeve 2515
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type threaded connection or
a
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standard threaded connection. In a preferred embodiment, the hydraulic slip
body 2520 is removably coupled to the sealing sleeve 2515 by a standard
threaded connection. The hydraulic slip body 2520 may be coupled to the slips
2525 using any number of conventional commercially available mechanical
couplings such as, for example, threaded connection or welding. In a preferred
embodiment, the hydraulic slip body 2520 is removably coupled to the slips
2525 by a threaded connection. The hydraulic slip body 2520 may be coupled to
the inner sealing mandrel 2530 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty type threaded connection, welding,
amorphous bonding or a standard threaded connection. In a preferred
embodiment, the hydraulic slip body 2520 is removably coupled to the inner
sealing mandrel 2530 by a standard threaded connection.
The hydraulic slips body 2520 preferably includes a fluid passage 2580
that is adapted to convey fluidic materials from the fluid passage 2575 into
the
fluid passage 2590. In a preferred embodiment, the fluid passage 2580 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The hydraulic slips body 2520 preferably includes fluid passages 2585
that are adapted to convey fluidic materials from the fluid passage 2580 into
the
pressure chambers of the hydraulic slips 2525. In this manner, the slips 2525
are activated upon the pressurization of the fluid passage 2580 into contact
with
the inside surface of the casing 2560. In a preferred embodiment, the fluid
passages 2585 are adapted to convey fluidic materials such as, for example,
water, drilling mud or lubricants at operating pressures and flow rates
ranging
from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The slips 2525 are coupled to the outside surface of the hydraulic slip
body 2520. During operation of the apparatus 2500, the slips 2525 are
activated
upon the pressurization of the fluid passage 2580 into contact with the inside
surface of the casing 2560. In this manner, the slips 2525 maintain the casing
2560 in a substantially stationary position.
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The slips 2525 preferably include the fluid passages 2585, the pressure
chambers 2605, spring bias 2610, and slip members 2615. The slips 2525 may
comprise any number of conventional commercially available hydraulic slips
such as, for example, RTTS packer tungsten carbide hydraulic slips or Model 3L
retrievable bridge plug with hydraulic slips. In a preferred embodiment, the
slips 2525 comprise RTTS packer tungsten carbide hydraulic slips available
from Halliburton Energy Services in order to optimally provide resistance to
axial movement of the casing 2560 during the expansion process.
The inner sealing mandrel 2530 is coupled to the hydraulic slip body
2520 and the lower sealing head 2540. The inner sealing mandrel 2530
preferably comprises a substantially hollow tubular member or members. The
inner sealing mandrel 2530 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the inner sealing mandrel 2530 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The inner sealing mandrel 2530 may be coupled to the hydraulic slip
body 2520 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the inner sealing
mandrel 2530 is removably coupled to the hydraulic slip body 2520 by a
standard threaded connection. The inner sealing mandrel 2530 may be
coupled to the lower sealing head 2540 using any number of conventional
commercially available mechanical couplings such as, for example, oilfield
country tubular goods specialty type threaded connection, drillpipe
connection,
welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the inner sealing mandrel 2530 is removably coupled to
the lower sealing head 2540 by a standard threaded connection.
The inner sealing mandrel 2530 preferably includes a fluid passage 2590
that is adapted to convey fluidic materials from the fluid passage 2580 into
the
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fluid passage 2600. In a preferred embodiment, the fluid passage 2590 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The upper sealing head 2535 is coupled to the outer sealing mandrel 2545
and expansion cone 2555. The upper sealing head 2535 is also movably coupled
to the outer surface of the inner sealing mandrel 2530 and the inner surface
of.
the casing 2560. In this manner, the upper sealing head 2535 reciprocates in
the axial direction. The radial clearance between the inner cylindrical
surface
of the upper sealing head 2535 and the outer surface of the inner sealing
mandrel 2530 may range, for example, from about 0.0025 to 0.05 inches. In a
preferred embodiment, the radial clearance between the inner cylindrical
surface of the upper sealing head 2535 and the outer surface of the inner
sealing mandrel 2530 ranges from about 0.005 to 0.01 inches in order to
optimally provide minimal radial clearance. The radial clearance between the
outer cylindrical surface of the upper sealing head 2535 and the inner surface
of
the casing 2560 may range, for example, from about 0.025 to 0.375 inches. In a
preferred embodiment, the radial clearance between the outer cylindrical
surface of the upper sealing head 2535 and the inner surface of the casing
2560
ranges from about 0.025 to 0.125 inches in order to optimally provide
stabilization for the expansion cone 2535 during the expansion process.
The upper sealing head 2535 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The upper sealing
head 2535 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, ow
alloy
steel, carbon steel, stainless steel or other similar high strength materials.
In a
preferred embodiment, the upper sealing head 2535 is fabricated from stainless
steel in order to optimally provide high strength, corrosion resistance, and
low
friction surfaces. The inner surface of the upper sealing head 2535 preferably
includes one or more annular sealing members 2620 for sealing the interface
between the upper sealing head 2535 and the inner sealing mandrel 2530. The
sealing members 2620 may comprise any number of conventional commercially
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available annular sealing members such as, for example, o-rings, polypak
seals,
or metal spring energized seals. In a preferred embodiment, the sealing
members 2620 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for a long axial stroke.
In a preferred embodiment, the upper sealing head 2535 includes a
shoulder 2625 for supporting the upper sealing head 2535, outer sealing
mandrel 2545, and expansion cone 2555 on the lower sealing head 2540.
The upper sealing head 2535 may be coupled to the outer sealing
mandrel 2545 using any number of conventional commercially available
mechanical couplings such as, for example, oilfield country tubular goods
specialty threaded connection, pipeline connection, welding, amorphous
bonding, or a standard threaded connection. In a preferred embodiment, the
upper sealing head 2535 is removably coupled to the outer sealing mandrel 2545
by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the upper sealing head 2535 and the outer sealing
mandrel 2545 includes one or more sealing members 2630 for fluidicly sealing
the interface between the upper sealing head 2535 and the outer sealing
mandrel 2545. The sealing members 2630 may comprise any number of
conventional commercially available sealing members such as, for example, o-
rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 2630 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
The lower sealing head 2540 is coupled to the inner sealing mandrel 2530
and the load mandrel 2550. The lower sealing head 2540 is also movably
coupled to the inner surface of the outer sealing mandrel 2545. In this
manner,
the upper sealing head 2535, outer sealing mandrel 2545, and expansion cone
2555 reciprocate in the axial direction.
The radial clearance between the outer surface of the lower sealing head
2540 and the inner surface of the outer sealing mandrel 2545 may range, for
example, from about 0.0025 to 0.05 inches. In a preferred embodiment, the
radial clearance between the outer surface of the lower sealing head 2540 and
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the inner surface of the outer sealing mandrel 2545 ranges from about 0.005 to
0.01 inches in order to optimally provide minimal radial clearance.
The lower sealing head 2540 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The lower sealing
head 2540 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel or other similar high strength
materials.
In a preferred embodiment, the lower sealing head 2540 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces. The outer surface of the lower sealing head 2540
preferably includes one or more annular sealing members 2635 for sealing the
interface between the lower sealing head 2540 and the outer sealing mandrel
2545. The sealing members 2635 may comprise any number of conventional
commercially available annular sealing members such as, for example, o-rings,
polypak seals, or metal spring energized seals. In a preferred embodiment, the
sealing members 2635 comprise polypak seals available from Parker Seals in
order to optimally provide sealing for a long axial stroke.
The lower sealing head 2540 may be coupled to the inner sealing mandrel
2530 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connections, oilfield country
tubular
goods specialty threaded connection, or a standard threaded connection. In a
preferred embodiment, the lower sealing head 2540 is removably coupled to the
inner sealing mandrel 2530 by a standard threaded connection. In a preferred
embodiment, the mechanical coupling between the lower sealing head 2540 and
the inner sealing mandrel 2530 includes one or more sealing members 2640 for
fluidicly sealing the interface between the lower sealing head 2540 and the
inner sealing mandrel 2530. The sealing members 2640 may comprise any
number of conventional commercially available sealing members such as, for
example, o-rings, polypak seals or metal spring energized seals. In a
preferred
embodiment, the sealing members 2640 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
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The lower sealing head 2540 may be coupled to the load mandrel 2550
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, welding, amorphous bonding or a standard
threaded connection. In a preferred embodiment, the lower sealing head 2540
is removably coupled to the load mandrel 2550 by a standard threaded
connection. In a preferred embodiment, the mechanical coupling between the
lower sealing head 2540 and the load mandrel 2550 includes one or more
sealing members 2645 for fluidicly sealing the interface between the lower
sealing head 2540 and the load mandrel 2550. The sealing members 2645 may
comprise any number of conventional commercially available sealing members
such as, for example, o-rings, polypak seals or metal spring energized seals.
In
a preferred embodiment, the sealing members 2645 comprise polypak seals
available from Parker Seals in order to optimally provide sealing for a long
axial
stroke.
In a preferred embodiment, the lower sealing head 2540 includes a throat
passage 2650 fluidicly coupled between the fluid passages 2590 and 2600. The
throat passage 2650 is preferably of reduced size and is adapted to receive
and
engage with a plug 2655, or other similar device. In this manner, the fluid
passage 2590 is fluidicly isolated from the fluid passage 2600. In this
manner,
the pressure chamber 2660 is pressurized.
The outer sealing mandrel 2545 is coupled to the upper sealing head 2535
and the expansion cone 2555. The outer sealing mandrel 2545 is also movably
coupled to the inner surface of the casing 2560 and the outer surface of the
lower sealing head 2540. In this manner, the upper sealing head 2535, outer
sealing mandrel 2545, and the expansion cone 2555 reciprocate in the axial
direction. The radial clearance between the outer surface of the outer sealing
mandrel 2545 and the inner surface of the casing 2560 may range, for example,
from about 0.025 to 0.375 inches. In a preferred embodiment, the radial
clearance between the outer surface of the outer sealing mandrel 2545 and the
inner surface of the casing 2560 ranges from about 0.025 to 0.125 inches in
order to optimally provide stabilization for the expansion cone 2535 during
the
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expansion process. The radial clearance between the inner surface of the outer
sealing mandrel 2545 and the outer surface of the lower sealing head 2540 may
range, for example, from about 0.005 to 0.01 inches. In a preferred
embodiment, the radial clearance between the inner surface of the outer
sealing
mandrel 2545 and the outer surface of the lower sealing head 2540 ranges from
about 0.005 to 0.01 inches in order to optimally provide minimal radial
clearance.
The outer sealing mandrel 2545 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The outer
sealing mandrel 2545 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the outer sealing mandrel 2545 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The outer sealing mandrel 2545 may be coupled to the upper sealing
head 2535 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the outer sealing
mandrel 2545 is removably coupled to the upper sealing head 2535 by a
standard threaded connection. The outer sealing mandrel 2545 may be coupled
to the expansion cone 2555 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty type threaded connection, welding,
amorphous bonding, or a standard threaded connection. In a preferred
embodiment, the outer sealing mandrel 2545 is removably coupled to the
expansion cone 2555 by a standard threaded connection.
The upper sealing head 2535, the lower sealing head 2540, the inner
sealing mandrel 2530, and the outer sealing mandrel 2545 together define a
pressure chamber 2660. The pressure chamber 2660 is fluidicly coupled to the
passage 2590 via one or more passages 2595. During operation of the apparatus
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2500, the plug 2655 engages with the throat passage 2650 to fluidicly isolate
the
fluid passage 2590 from the fluid passage 2600. The pressure chamber 2660 is
then pressurized which in turn causes the upper sealing head 2535, outer
sealing mandrel 2545, and expansion cone 2555 to reciprocate in the axial
direction. The axial motion of the expansion cone 2555 in turn expands the
casing 2560 in the radial direction.
The load mandrel 2550 is coupled to the lower sealing head 2540. The
load mandrel 2550 preferably comprises an annular member having
substantially cylindrical inner and outer surfaces. The load mandrel 2550 may
be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy
steel,
carbon steel, stainless steel or other similar high strength materials. In a
preferred embodiment, the load mandrel 2550 is fabricated from stainless steel
in order to optimally provide high strength, corrosion resistance, and low
friction surfaces.
The load mandrel 2550 may be coupled to the lower sealing head 2540
using any number of conventional commercially available mechanical couplings
such as, for example, oilfield country tubular goods, drillpipe connection,
welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the load mandrel 2550 is removably coupled to the lower
sealing head 2540 by a standard threaded connection.
The load mandrel 2550 preferably includes a fluid passage 2600 that is
adapted to convey fluidic materials from the fluid passage 2590 to the region
outside of the apparatus 2500. In a preferred embodiment, the fluid passage
2600 is adapted to convey fluidic materials such as, for example, cement,
epoxy,
water, drilling mud, or lubricants at operating pressures and flow rates
ranging,
for example, from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The expansion cone 2555 is coupled to the outer sealing mandrel 2545.
The expansion cone 2555 is also movably coupled to the inner surface of the
casing 2560. In this manner, the upper sealing head 2535, outer sealing
mandrel 2545, and the expansion cone 2555 reciprocate in the axial direction.
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The reciprocation of the expansion cone 2555 causes the casing 2560 to expand
in the radial direction.
The expansion cone 2555 preferably comprises an annular member
having substantially cylindrical inner and conical outer surfaces. The outside
radius of the outside conical surface may range, for example, from about 2 to
34
inches. In a preferred embodiment, the outside radius of the outside conical
surface ranges from about 3 to 28 in order to optimally provide radial
expansion
for the widest variety of tubular casings. The axial length of the expansion
cone
2555 may range, for example, from about 2 to 8 times the largest outside
diameter of the expansion cone 2535. In a preferred embodiment, the axial
length of the expansion cone 2535 ranges from about 3 to 5 times the largest
outside diameter of the expansion cone 2535 in order to optimally provide
stabilization and centralization of the expansion cone 2535 during the
expansion process. In a particularly preferred embodiment, the maximum
outside diameter of the expansion cone 2555 is between about 95 to 99 % of the
inside diameter of the existing wellbore that the casing 2560 will be joined
with.
In a preferred embodiment, the angle of attack of the expansion cone 2555
ranges from about 5 to 30 degrees in order to optimally balance frictional
forces
and radial expansion forces. The optimum angle of attack of the expansion
cone 2535 will vary as a function of the particular operational features of
the
expansion operation.
The expansion cone 2555 may be fabricated from any number of
conventional commercially available materials such as, for example, machine
tool steel, nitride steel, titanium, tungsten carbide, ceramics or other
similar
high strength materials. In a preferred embodiment, the expansion cone 2555
is fabricated from D2 machine tool steel in order to optimally provide high
strength, and resistance to wear and galling. In a particularly preferred
embodiment, the outside surface of the expansion cone 2555 has a surface
hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
high strength and wear resistance.
The expansion cone 2555 may be coupled to the outside sealing mandrel
2545 using any number of conventional commercially available mechanical
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couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty threaded connection, welding, amorphous bonding or a standard
threaded connection. In a preferred embodiment, the expansion cone 2555 is
coupled to the outside sealing mandrel 2545 using a standard threaded
connection in order to optimally provide high strength and easy replacement of
the expansion cone 2555.
The casing 2560 is removably coupled to the slips 2525 and expansion
cone 2555. The casing 2560 preferably comprises a tubular member. The
casing 2560 may be fabricated from any number of conventional commercially
available materials such as, for example, slotted tubulars, oilfield country
tubular goods, low alloy steel, carbon steel, stainless steel or other similar
high
strength materials. In a preferred embodiment, the casing 2560 is fabricated
from oilfield country tubular goods available from various foreign and
domestic
steel mills in order to optimally provide high strength using standardized
materials.
In a preferred embodiment, the upper end 2665 of the casing 2560
includes a thin wall section 2670 and an outer annular sealing member 2675.
In a preferred embodiment, the wall thickness of the thin wall section 2670 is
about 50 to 100 % of the regular wall thickness of the casing 2560. In this
manner, the upper end 2665 of the casing 2560 may be easily radially expanded
and deformed into intimate contact with the lower end of an existing section
of
wellbore casing. In a preferred embodiment, the lower end of the existing
section of casing also includes a thin wall section. In this manner, the
radial
expansion of the thin walled section 2670 of casing 2560 into the thin walled
section of the existing wellbore casing results in a wellbore casing having a
substantially constant inside diameter.
The annular sealing member 2675 may be fabricated from any number of
conventional commercially available sealing materials such as, for example,
epoxy, rubber, metal, or plastic. In a preferred embodiment, the annular
sealing member 2675 is fabricated from StrataLock epoxy in order to optimally
provide compressibility and resistance to wear. The outside diameter of the
annular sealing member 2675 preferably ranges from about 70 to 95 % of the
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inside diameter of the lower section of the wellbore casing that the casing
2560
is joined to. In this manner, after radial expansion, the annular sealing
member 2670 optimally provides a fluidic seal and also preferably optimally
provides sufficient frictional force with the inside surface of the existing
section
of wellbore casing during the radial expansion of the casing 2560 to support
the
casing 2560.
In a preferred embodiment, the lower end 2680 of the casing 2560
includes a thin wall section 2685 and an outer annular sealing member 2690.
In a preferred embodiment, the wall thickness of the thin wall section 2685 is
about 50 to 100 % of the regular wall thickness of the casing 2560. In this
manner, the lower end 2680 of the casing 2560 may be easily expanded and
deformed. Furthermore, in this manner, an other section of casing may be
easily joined with the lower end 2680 of the casing 2560 using a radial
expansion process. In a preferred embodiment, the upper end of the other
section of casing also includes a thin wall section. In this manner, the
radial
expansion of the thin walled section of the upper end of the other casing into
the thin walled section 2685 of the lower end 2680 of the casing 2560 results
in
a wellbore casing having a substantially constant inside diameter.
The annular sealing member 2690 may be fabricated from any number of
conventional commercially available sealing materials such as, for example,
rubber, metal, plastic or epoxy. In a preferred embodiment, the annular
sealing
member 2690 is fabricated from StrataLock epoxy in order to optimally provide
compressibility and resistance to wear. The outside diameter of the annular
sealing member 2690 preferably ranges from about ?0 to 95 % of the inside
diameter of the lower section of the existing wellbore casing that the casing
2560 is joined to. In this manner, after radial expansion, the annular sealing
member 2690 preferably provides a fluidic seal and also preferably provides
sufficient frictional force with the inside wall of the wellbore during the
radial
expansion of the casing 2560 to support the casing 2560.
During operation, the apparatus 2500 is preferably positioned in a
wellbore with the upper end 2665 of the casing 2560 positioned in an
overlapping relationship with the lower end of an existing wellbore casing. In
a
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particularly preferred embodiment, the thin wall section 2670 of the casing
2560 is positioned in opposing overlapping relation with the thin wall section
and outer annular sealing member of the lower end of the existing section of
wellbore casing. In this manner, the radial expansion of the casing 2560 will
compress the thin wall sections and annular compressible members of the upper
end 2665 of the casing 2560 and the lower end of the existing wellbore casing
into intimate contact. During the positioning of the apparatus 2500 in the
wellbore, the casing 2560 is supported by the expansion cone 2555.
After positioning of the apparatus 2500, a first fluidic material is then
pumped into the fluid passage 2565. The first fluidic material may comprise
any number of conventional commercially available materials such as, for
example, cement, water, slag-mix, epoxy or drilling mud. In a preferred
embodiment, the first fluidic material comprises a hardenable fluidic sealing
material such as, for example, cement, epoxy, or slag-mix in order to
optimally
provide a hardenable outer annular body around the expanded casing 2560.
The first fluidic material may be pumped into the fluid passage 2565 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi and 0 to 3,000 gallons/minute. In a preferred embodiment, the first
fluidic
material is pumped into the fluid passage 2565 at operating pressures and flow
rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order
to optimally provide operational efficiency
The first fluidic material pumped into the fluid passage 2565 passes
through the fluid passages 2570, 2575, 2580, 2590, 2600 and then outside of
the
apparatus 2500. The first fluidic material then preferably fills the annular
region between the outside of the apparatus 2500 and the interior walls of the
wellbore.
The plug 2655 is then introduced into the fluid passage 2565. The plug
2655 lodges in the throat passage 2650 and fluidicly isolates and blocks off
the
fluid passage 2590. In a preferred embodiment, a couple of volumes of a non-
hardenable fluidic material are then pumped into the fluid passage 2565 in
order to remove any hardenable fluidic material contained within and to ensure
that none of the fluid passages are blocked.
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A second fluidic material is then pumped into the fluid passage 2565.
The second fluidic material may comprise any number of conventional
commercially available materials such as, for example, water, drilling gases,
drilling mud or lubricant. In a preferred embodiment, the second fluidic
material comprises a non-hardenable fluidic material such as, for example,
water, drilling mud, or lubricant in order to optimally provide pressurization
of
the pressure chamber 2660 and minimize friction.
The second fluidic material may be pumped into the fluid passage 2565 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi and 0 to 4,500 gallons/minute. In a preferred embodiment, the second
fluidic material is pumped into the fluid passage 2565 at operating pressures
and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute
in order to optimally provide operational efficiency.
The second fluidic material pumped into the fluid passage 2565 passes
through the fluid passages 2570, 2575, 2580, 2590 and into the pressure
chambers 2605 of the slips 2525, and into the pressure chamber 2660.
Continued pumping of the second fluidic material pressurizes the pressure
chambers 2605 and 2660.
The pressurization of the pressure chambers 2605 causes the slip
members 2525 to expand in the radial direction and grip the interior surface
of
the casing 2560. The casing 2560 is then preferably maintained in a
substantially stationary position.
The pressurization of the pressure chamber 2660 causes the upper
sealing head 2535, outer sealing mandrel 2545 and expansion cone 2555 to
move in an axial direction relative to the casing 2560. In this manner, the
expansion cone 2555 will cause the casing 2560 to expand in the radial
direction, beginning with the lower end 2685 of the casing 2560.
During the radial expansion process, the casing 2560 is prevented from
moving in an upward direction by the slips 2525. A length of the casing 2560
is
then expanded in the radial direction through the pressurization of the
pressure
chamber 2660. The length of the casing 2560 that is expanded during the
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expansion process will be proportional to the stroke length of the upper
sealing
head 2535, outer sealing mandrel 2545, and expansion cone 2555.
Upon the completion of a stroke, the operating pressure of the second
fluidic material is reduced and the upper sealing head 2535, outer sealing
mandrel 2545, and expansion cone 2555 drop to their rest positions with the
casing 2560 supported by the expansion cone 2555. The position of the
drillpipe
2505 is preferably adjusted throughout the radial expansion process in order
to
maintain the overlapping relationship between the thin walled sections of the
lower end of the existing wellbore casing and the upper end of the casing
2560.
In a preferred embodiment, the stroking of the expansion cone 2555 is then
repeated, as necessary, until the thin walled section 2670 of the upper end
2665
of the casing 2560 is expanded into the thin walled section of the lower end
of
the existing wellbore casing. In this manner, a wellbore casing is formed
including two adjacent sections of casing having a substantially constant
inside
diameter. This process may then be repeated for the entirety of the wellbore
to
provide a wellbore casing thousands of feet in length having a substantially
constant inside diameter.
In a preferred embodiment, during the final stroke of the expansion cone
2555, the slips 2525 are positioned as close as possible to the thin walled
section
2670 of the upper end 2665 of the casing 2560 in order minimize slippage
between the casing 2560 and the existing wellbore casing at the end of the
radial expansion process. Alternatively, or in addition, the outside diameter
of
the annular sealing member 2675 is selected to ensure sufficient interference
fit
with the inside diameter of the lower end of the existing casing to prevent
axial
displacement of the casing 2560 during the final stroke. Alternatively, or in
addition, the outside diameter of the annular sealing member 2690 is selected
to
provide an interference fit with the inside walls of the wellbore at an
earlier
point in the radial expansion process so as to prevent further axial
displacement
of the casing 2560. In this final alternative, the interference fit is
preferably
selected to permit expansion of the casing 2560 by pulling the expansion cone
2555 out of the wellbore, without having to pressurize the pressure chamber
2660.
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During the radial expansion process, the pressurized areas of the
apparatus 2500 are preferably limited to the fluid passages 2565, 2570, 2575,
2580, and 2590, the pressure chambers 2605 within the slips 2525, and the
pressure chamber 2660. No fluid pressure acts directly on the casing 2560.
This permits the use of operating pressures higher than the casing 2560 could
normally withstand.
Once the casing 2560 has been completely expanded off of the expansion
cone 2555, the remaining portions of the apparatus 2500 are removed from the
wellbore. In a preferred embodiment, the contact pressure between the
deformed thin wall sections and compressible annular members of the lower
end of the existing casing and the upper end 2665 of the casing 2560 ranges
from about 400 to 10,000 psi in order to optimally support the casing 2560
using the existing wellbore casing.
In this manner, the casing 2560 is radially expanded into contact with an
existing section of casing by pressurizing the interior fluid passages 2565,
2570,
2575, 2580, and 2590, the pressure chambers of the slips 2605 and the pressure
chamber 2660 of the apparatus 2500.
In a preferred embodiment, as required, the annular body of hardenable
fluidic material is then allowed to cure to form a rigid outer annular body
about
the expanded casing 2560. In the case where the casing 2560 is slotted, the
cured fluidic material preferably permeates and envelops the expanded casing
2560. The resulting new section of wellbore casing includes the expanded
casing 2560 and the rigid outer annular body. The overlapping joint between
the pre-existing wellbore casing and the expanded casing 2560 includes the
deformed thin wall sections and the compressible outer annular bodies. The
inner diameter of the resulting combined wellbore casings is substantially
constant. In this manner, a mono-diameter wellbore casing is formed. This
process of expanding overlapping tubular members having thin wall end
portions with compressible annular bodies into contact can be repeated for the
entire length of a wellbore. In this manner, a mono-diameter wellbore casing
can be provided for thousands of feet in a subterranean formation.
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In a preferred embodiment, as the expansion cone 2555 nears the upper
end 2665 of the casing 2560, the operating pressure of the second fluidic
material is reduced in order to minimize shock to the apparatus 2500. In an
alternative embodiment, the apparatus 2500 includes a shock absorber for
absorbing the shock created by the completion of the radial expansion of the
casing 2560.
In a preferred embodiment, the reduced operating pressure of the second
fluidic material ranges from about 100 to 1,000 psi as the expansion cone 2555
nears the end of the casing 2560 in order to optimally provide reduced axial
movement and velocity of the expansion cone 2555. In a preferred embodiment,
the operating pressure of the second fluidic material is reduced during the
return stroke of the apparatus 2500 to the range of about 0 to 500 psi in
order
minimize the resistance to the movement of the expansion cone 2555 during the
return stroke. In a preferred embodiment, the stroke length of the apparatus
2500 ranges from about 10 to 45 feet in order to optimally provide equipments
lengths that can be easily handled using typical oil well rigging equipment
and
also minimize the frequency at which apparatus 2500 must be re-stroked.
In an alternative embodiment, at least a portion of the upper sealing
head 2535 includes an expansion cone for radially expanding the casing 2560
during operation of the apparatus 2500 in order to increase the surface area
of
the casing 2560 acted upon during the radial expansion process. In this
manner, the operating pressures can be reduced.
Alternatively, the apparatus 2500 may be used to join a first section of
pipeline to an existing section of pipeline. Alternatively, the apparatus 2500
may be used to directly line the interior of a wellbore with a casing, without
the
use of an outer annular layer of a hardenable material. Alternatively, the
apparatus 2500 may be used to expand a tubular support member in a hole.
Referring now to Figures 19, 19a and 19b, another embodiment of an
apparatus 2700 for expanding a tubular member will be described. The
apparatus 2700 preferably includes a drillpipe 2705, an innerstring adapter
2710, a sealing sleeve 2715, a first inner sealing mandrel 2720, a first upper
sealing head 2725, a first lower sealing head 2730, a first outer sealing
mandrel
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2735, a second inner sealing mandrel 2740, a second upper sealing head 2745, a
second lower sealing head 2750, a second outer sealing mandrel 2755, a load
mandrel 2760, an expansion cone 2765, a mandrel launcher 2770, a mechanical
slip body 2775, mechanical slips 2780, drag blocks 2785, casing 2790, and
fluid
passages 2795, 2800, 2805, 2810, 2815, 2820, 2825, and 2830.
The drillpipe 2705 is coupled to the innerstring adapter 2710. During
operation of the apparatus 2700, the drillpipe 2705 supports the apparatus
2700. The drillpipe 2705 preferably comprises a substantially hollow tubular
member or members. The drillpipe 2705 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel, or
other
similar high strength materials. In a preferred embodiment, the drillpipe 2705
is fabricated from coiled tubing in order to facilitate the placement of the
apparatus 2700 in non-vertical wellbores. The drillpipe 2705 may be coupled to
the innerstring adapter 2710 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty threaded connection, or a standard
threaded connection. In a preferred embodiment, the drillpipe 2705 is
removably coupled to the innerstring adapter 2710 by a drillpipe connection in
order to optimally provide high strength and easy disassembly.
The drillpipe 2705 preferably includes a fluid passage 2795 that is
adapted to convey fluidic materials from a surface location into the fluid
passage 2800. In a preferred embodiment, the fluid passage 2795 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud or lubricants at operating pressures and flow rates ranging from about 0
to
9,000 psi and 0 to 3,000 gallons/minute.
The innerstring adapter 2710 is coupled to the drill string 2705 and the
sealing sleeve 2715. The innerstring adapter 2710 preferably comprises a
substantially hollow tubular member or members. The innerstring adapter
2710 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel or other similar high strength
materials.
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In a preferred embodiment, the innerstring adapter 2710 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces.
The innerstring adapter 2710 may be coupled to the drill string 2705
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty threaded connection, or a standard threaded connection. In a
preferred embodiment, the innerstring adapter 2710 is removably coupled to
the drill pipe 2705 by a standard threaded connection in order to optimally
provide high strength and easy disassembly. The innerstring adapter 2710 may
be coupled to the sealing sleeve 2715 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty type threaded connection,
ratchet-latch type threaded connection or a standard threaded connection. In a
preferred embodiment, the innerstring adapter 2710 is removably coupled to
the sealing sleeve 2715 by a standard threaded connection.
The innerstring adapter 2710 preferably includes a fluid passage 2800
that is adapted to convey fluidic materials from the fluid passage 2795 into
the
fluid passage 2805. In a preferred embodiment, the fluid passage 2800 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The sealing sleeve 2715 is coupled to the innerstring adapter 2710 and
the first inner sealing mandrel 2720. The sealing sleeve 2715 preferably
comprises a substantially hollow tubular member or members. The sealing
sleeve 2715 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel or other similar high strength
materials.
In a preferred embodiment, the sealing sleeve 2715 is fabricated from
stainless
steel in order to optimally provide high strength, corrosion resistance, and
low
friction surfaces.
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The sealing sleeve 2715 may be coupled to the innerstring adapter 2710
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, welding, amorphous bonding, or a standard
threaded connection. In a preferred embodiment, the sealing sleeve 2715 is
removably coupled to the innerstring adapter 2710 by a standard threaded
connector. The sealing sleeve 2715 may be coupled to the first inner sealing
mandrel 2720 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, welding, amorphous bonding
or a standard threaded connection. In a preferred embodiment, the sealing
sleeve 2715 is removably coupled to the inner sealing mandrel 2720 by a
standard threaded connection.
The sealing sleeve 2715 preferably includes a fluid passage 2802 that is
adapted to convey fluidic materials from the fluid passage 2800 into the fluid
passage 2805. In a preferred embodiment, the fluid passage 2802 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud or lubricants at operating pressures and flow rates ranging from about 0
to
9,000 psi and 0 to 3,000 gallons/minute.
The first inner sealing mandrel 2720 is coupled to the sealing sleeve 2715
and the first lower sealing head 2730. The first inner sealing mandrel 2720
preferably comprises a substantially hollow tubular member or members. The
first inner sealing mandrel 2720 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other
similar high strength materials. In a preferred embodiment, the first inner
sealing mandrel 2720 is fabricated from stainless steel in order to optimally
provide high strength, corrosion resistance, and low friction surfaces.
The first inner sealing mandrel 2720 may be coupled to the sealing sleeve
2715 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection oilfield country tubular
goods specialty threaded connection, welding, amorphous bonding, or a
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standard threaded connection. In a preferred embodiment, the first inner
sealing mandrel 2720 is removably coupled to the sealing sleeve 2715 by a
standard threaded connection. The first inner sealing mandrel 2720 may be
coupled to the first lower sealing head 2730 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty type threaded connection,
welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the first inner sealing mandrel 2720 is removably
coupled to the first lower sealing head 2730 by a standard threaded
connection.
The first inner sealing mandrel 2720 preferably includes a fluid passage
2805 that is adapted to convey fluidic materials from the fluid passage 2802
into
the fluid passage 2810. In a preferred embodiment, the fluid passage 2805 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The first upper sealing head 2725 is coupled to the first outer sealing
mandrel 2735, the second upper sealing head 2745, the second outer sealing
mandrel 2755, and the expansion cone 2765. The first upper sealing head 2725
is also movably coupled to the outer surface of the first inner sealing
mandrel
2720 and the inner surface of the casing 2790. In this manner, the first upper
sealing head 2725 reciprocates in the axial direction. The radial clearance
between the inner cylindrical surface of the first upper sealing head 2725 and
the outer surface of the first inner sealing mandrel 2720 may range, for
example, from about 0.0025 to 0.05 inches. In a preferred embodiment, the
radial clearance between the inner cylindrical surface of the first upper
sealing
head 2725 and the outer surface of the first inner sealing mandrel 2720 ranges
from about 0.005 to 0.125 inches in order to optimally provide minimal radial
clearance. The radial clearance between the outer cylindrical surface of the
first
upper sealing head 2725 and the inner surface of the casing 2790 may range,
for
example, from about 0.025 to 0.375 inches. In a preferred embodiment, the
radial clearance between the outer cylindrical surface of the first upper
sealing
head 2725 and the inner surface of the casing 2790 ranges from about 0.025 to
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0.125 inches in order to optimally provide stabilization for the expansion
cone
2765 during the expansion process.
The first upper sealing head 2725 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The first
upper sealing head 2725 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the first upper sealing head 2725 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance and low friction surfaces. The inner surface of the first
upper sealing head 2725 preferably includes one or more annular sealing
members 2835 for sealing the interface between the first upper sealing head
2725 and the first inner sealing mandrel 2720. The sealing members 2835 may
comprise any number of conventional commercially available annular sealing
members such as, for example, o-rings, polypak seals or metal spring energized
seals. In a preferred embodiment, the sealing members 2835 comprise polypak
seals available from Parker Seals in order to optimally provide sealing for
long
axial strokes.
In a preferred embodiment, the first upper sealing head 2725 includes a
shoulder 2840 for supporting the first upper sealing head 2725 on the first
lower sealing head 2730.
The first upper sealing head 2725 may be coupled to the first outer
sealing mandrel 2735 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty threaded connection, welding, amorphous bonding or a
standard threaded connection. In a preferred embodiment, the first upper
sealing head 2725 is removably coupled to the first outer sealing mandrel 2735
by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the first upper sealing head 2725 and the first
outer sealing mandrel 2735 includes one or more sealing members 2845 for
fluidicly sealing the interface between the first upper sealing head 2725 and
the
first outer sealing mandrel 2735. The sealing members 2845 may comprise any
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number of conventional commercially available sealing members such as, for
example, o-rings, polypak seals or metal spring energized seals. In a
preferred
embodiment, the sealing members 2845 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for long axial strokes.
The first lower sealing head 2730 is coupled to the first inner sealing
mandrel 2720 and the second inner sealing mandrel 2740. The first lower
sealing head 2730 is also movably coupled to the inner surface of the first
outer
sealing mandrel 2735. In this manner, the first upper sealing head 2725 and
first outer sealing mandrel 2735 reciprocate in the axial direction. The
radial
clearance between the outer surface of the first lower sealing head 2730 and
the
inner surface of the first outer sealing mandrel 2735 may range, for example,
from about 0.0025 to 0.05 inches. In a preferred embodiment, the radial
clearance between the outer surface of the first lower sealing head 2730 and
the
inner surface of the first outer sealing mandrel 2735 ranges from about 0.005
to
0.01 inches in order to optimally provide minimal radial clearance.
The first lower sealing head 2730 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The first
lower sealing head 2730 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the first lower sealing head 2730 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The outer surface of the
first
lower sealing head 2730 preferably includes one or more annular sealing
members 2850 for sealing the interface between the first lower sealing head
2730 and the first outer sealing mandrel 2735. The sealing members 2850 may
comprise any number of conventional commercially available annular sealing
members such as, for example, o-rings, polypak seals or metal spring energized
seals. In a preferred embodiment, the sealing members 2850 comprise polypak
seals available from Parker Seals in order to optimally provide sealing for
long
axial strokes.
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The first lower sealing head 2730 may be coupled to the first inner
sealing mandrel 2720 using any number of conventional commercially available
mechanical couplings such as, for example, oilfield country tubular goods
specialty threaded connections, welding, amorphous bonding, or standard
threaded connection. In a preferred embodiment, the first lower sealing head
2730 is removably coupled to the first inner sealing mandrel 2720 by a
standard
threaded connection. In a preferred embodiment, the mechanical coupling
between the first lower sealing head 2730 and the first inner sealing mandrel
2720 includes one or more sealing members 2855 for fluidicly sealing the
interface between the first lower sealing head 2730 and the first inner
sealing
mandrel 2720. The sealing members 2855 may comprise any number of
conventional commercially available sealing members such as, for example, o-
rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 2855 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for long axial strokes.
The first lower sealing head 2730 may be coupled to the second inner
sealing mandrel 2740 using any number of conventional commercially available
mechanical couplings such as, for example, oilfield country tubular goods
specialty threaded connection, welding, amorphous bonding, or a standard
threaded connection. In a preferred embodiment, the lower sealing head 2730
is removably coupled to the second inner sealing mandrel 2740 by a standard
threaded connection. In a preferred embodiment, the mechanical coupling
between the first lower sealing head 2730 and the second inner sealing mandrel
2740 includes one or more sealing members 2860 for fluidicly sealing the
interface between the first lower sealing head 2730 and the second inner
sealing
mandrel 2740. The sealing members 2860 may comprise any number of
conventional commercially available sealing members such as, for example, o-
rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 2860 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for long axial strokes.
The first outer sealing mandrel 2735 is coupled to the first upper sealing
head 2725, the second upper sealing head 2745, the second outer sealing
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mandrel 2755, and the expansion cone 2765. The first outer sealing mandrel
2735 is also movably coupled to the inner surface of the casing 2790 and the
outer surface of the first lower sealing head 2730. In this manner, the first
upper sealing head 2725, first outer sealing mandrel 2735, second upper
sealing
head 2745, second outer sealing mandrel 2755, and the expansion cone 2765
reciprocate in the axial direction. The radial clearance between the outer
surface of the first outer sealing mandrel 2735 and the inner surface of the
casing 2790 may range, for example, from about 0.025 to 0.375 inches. In a
preferred embodiment, the radial clearance between the outer surface of the
first outer sealing mandrel 2735 and the inner surface of the casing 2790
ranges
from about 0.025 to 0.125 inches in order to optimally provide stabilization
for
the expansion cone 2765 during the expansion process. The radial clearance
between the inner surface of the first outer sealing mandrel 2735 and the
outer
surface of the first lower sealing head 2730 may range, for example, from
about
0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance between
the inner surface of the first outer sealing mandrel 2735 and the outer
surface
of the first lower sealing head 2730 ranges from about 0.005 to 0.01 inches in
order to optimally provide minimal radial clearance.
The outer sealing mandrel 1935 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The first
outer sealing mandrel 2735 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the first outer sealing mandrel 2735 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The first outer sealing mandrel 2735 may be coupled to the first upper
sealing head 2725 using any number of conventional commercially available
mechanical couplings such as, for example, oilfield country tubular goods,
welding, amorphous bonding, or a standard threaded connection. In a
preferred embodiment, the first outer sealing mandrel 2735 is removably
coupled to the first upper sealing head 2725 by a standard threaded
connection.
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The first outer sealing mandrel 2735 may be coupled to the second upper
sealing head 2745 using any number of conventional commercially available
mechanical couplings such as, for example, oilfield country tubular goods
specialty threaded connection, welding, amorphous bonding, or a standard
threaded connection. In a preferred embodiment, the first outer sealing
mandrel 2735 is removably coupled to the second upper sealing head 2745 by a
standard threaded connection.
The second inner sealing mandrel 2740 is coupled to the first lower
sealing head 2730 and the second lower sealing head 2750. The second inner
sealing mandrel 2740 preferably comprises a substantially hollow tubular
member or members. The second inner sealing mandrel 2740 may be fabricated
from any number of conventional commercially available materials such as, for
example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless
steel or other similar high strength materials. In a preferred embodiment, the
second inner sealing mandrel 2740 is fabricated from stainless steel in order
to
optimally provide high strength, corrosion resistance, and low friction
surfaces.
The second inner sealing mandrel 2740 may be coupled to the first lower
sealing head 2730 using any number of conventional commercially available
mechanical couplings such as, for example, oilfield country tubular goods
specialty threaded connection, welding, amorphous bonding, or a standard
threaded connection. In a preferred embodiment, the second inner sealing
mandrel 2740 is removably coupled to the first lower sealing head 2740 by a
standard threaded connection. The mechanical coupling between the second
inner sealing mandrel 2740 and the first lower sealing head 2730 preferably
includes sealing members 2860.
The second inner sealing mandrel 2740 may be coupled to the second
lower sealing head 2750 using any number of conventional commercially
available mechanical couplings such as, for example, oilfield country tubular
goods specialty threaded connection, welding, amorphous bonding, or a
standard threaded connection. In a preferred embodiment, the second inner
sealing mandrel 2720 is removably coupled to the second lower sealing head
2750 by a standard threaded connection. In a preferred embodiment, the
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mechanical coupling between the second inner sealing mandrel 2740 and the
second lower sealing head 2750 includes one or more sealing members 2865.
The sealing members 2865 may comprise any number of conventional
commercially available seals such as, for example, o-rings, polypak seals or
metal spring energized seals. In a preferred embodiment, the sealing members
2865 comprise polypak seals available from Parker Seals.
The second inner sealing mandrel 2740 preferably includes a fluid
passage 2810 that is adapted to convey fluidic materials from the fluid
passage
2805 into the fluid passage 2815. In a preferred embodiment, the fluid passage
2810 is adapted to convey fluidic materials such as, for example, cement,
epoxy,
water, drilling mud or lubricants at operating pressures and flow rates
ranging
from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The second upper sealing head 2745 is coupled to the first upper sealing
head 2725, the first outer sealing mandrel 2735, the second outer sealing
mandrel 2755, and the expansion cone 2765. The second upper sealing head
2745 is also movably coupled to the outer surface of the second inner sealing
mandrel 2740 and the inner surface of the casing 2790. In this manner, the
second upper sealing head 2745 reciprocates in the axial direction. The radial
clearance between the inner cylindrical surface of the second upper sealing
head
2745 and the outer surface of the second inner sealing mandrel 2740 may range,
for example, from about 0.0025 to 0.05 inches. In a preferred embodiment, the
radial clearance between the inner cylindrical surface of the second upper
sealing head 2745 and the outer surface of the second inner sealing mandrel
2740 ranges from about 0.005 to 0.01 inches in order to optimally provide
minimal radial clearance. The radial clearance between the outer cylindrical
surface of the second upper sealing head 2745 and the inner surface of the
casing 2790 may range, for example, from about 0.025 to .375 inches. In a
preferred embodiment, the radial clearance between the outer cylindrical
surface of the second upper sealing head 2745 and the inner surface of the
casing 2790 ranges from about 0.025 to 0.125 inches in order to optimally
provide stabilization for the expansion cone 2765 during the expansion
process.
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The second upper sealing head 2745 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The second
upper sealing head 2745 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the second upper sealing head 2745 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The inner surface of the
second
upper sealing head 2745 preferably includes one or more annular sealing
members 2870 for sealing the interface between the second upper sealing head
2745 and the second inner sealing mandrel 2740. The sealing members 2870
may comprise any number of conventional commercially available annular
sealing members such as, for example, o-rings, polypak seals, or metal spring
energized seals. In a preferred embodiment, the sealing members 2870
comprise polypak seals available from Parker Seals in order to optimally
provide sealing for long axial strokes.
In a preferred embodiment, the second upper sealing head 2745 includes
a shoulder 2875 for supporting the second upper sealing head 2745 on the
second lower sealing head 2750.
The second upper sealing head 2745 may be coupled to the first outer
sealing mandrel 2735 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty threaded connection, ratchet-latch type threaded
connection, or a standard threaded connection. In a preferred embodiment, the
second upper sealing head 2745 is removably coupled to the first outer sealing
mandrel 2735 by a standard threaded connection. In a preferred embodiment,
the mechanical coupling between the second upper sealing head 2745 and the
first outer sealing mandrel 2735 includes one or more sealing members 2880 for
fluidicly sealing the interface between the second upper sealing head 2745 and
the first outer sealing mandrel 2735. The sealing members 2880 may comprise
any number of conventional commercially available sealing members such as,
for example, o-rings, polypak seals or metal spring energized seals. In a
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preferred embodiment, the sealing members 2880 comprise polypak seals
available from Parker Seals in order to optimally provide sealing for a long
axial
stroke.
The second upper sealing head 2745 may be coupled to the second outer
sealing mandrel 2755 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, or a standard threaded
connection. In a preferred embodiment, the second upper sealing head 2745 is
removably coupled to the second outer sealing mandrel 2755 by a standard
threaded connection. In a preferred embodiment, the mechanical coupling
between the second upper sealing head 2745 and the second outer sealing
mandrel 2755 includes one or more sealing members 2885 for fluidicly sealing
the interface between the second upper sealing head 2745 and the second outer
sealing mandrel 2755. The sealing members 2885 may comprise any number of
conventional commercially available sealing members such as, for example, o-
rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 2885 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for long axial strokes.
The second lower sealing head 2750 is coupled to the second inner
sealing mandrel 2740 and the load mandrel 2760. The second lower sealing
head 2750 is also movably coupled to the inner surface of the second outer
sealing mandrel 2755. In this manner, the first upper sealing head 2725, the
first outer sealing mandrel 2735, second upper sealing head 2745, second outer
sealing mandrel 2755, and the expansion cone 2765 reciprocate in the axial
direction. The radial clearance between the outer surface of the second lower
sealing head 2750 and the inner surface of the second outer sealing mandrel
2755 may range, for example, from about 0.0025 to 0.05 inches. In a preferred
embodiment, the radial clearance between the outer surface of the second lower
sealing head 2750 and the inner surface of the second outer sealing mandrel
2755 ranges from about 0.005 to 0.01 inches in order to optimally provide
minimal radial clearance.
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The second lower sealing head 2750 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The second
lower sealing head 2750 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the second lower sealing head 2750 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The outer surface of the
second
lower sealing head 2750 preferably includes one or more annular sealing
members 2890 for sealing the interface between the second lower sealing head
2750 and the second outer sealing mandrel 2755. The sealing members 2890
may comprise any number of conventional commercially available annular
sealing members such as, for example, o-rings, polypak seals or metal spring
energized seals. In a preferred embodiment, the sealing members 2890
comprise polypak seals available from Parker Seals in order to optimally
provide sealing for long axial strokes.
The second lower sealing head 2750 may be coupled to the second inner
sealing mandrel 2740 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty threaded connection, ratchet-latch type threaded
connection, or a standard threaded connection. In a preferred embodiment, the
second lower sealing head 2750 is removably coupled to the second inner
sealing
mandrel 2740 by a standard threaded connection. In a preferred embodiment,
the mechanical coupling between the second lower sealing head 2750 and the
second inner sealing mandrel 2740 includes one or more sealing members 2895
for fluidicly sealing the interface between the second sealing head 2750and
the
second sealing mandrel 2740. The sealing members 2895 may comprise any
number of conventional commercially available sealing members such as, for
example, o-rings, polypak seals or metal spring energized seals. In a
preferred
embodiment, the sealing members 2895 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
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The second lower sealing head 2750 may be coupled to the load mandrel
2760 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield tubular goods
specialty threaded connection, ratchet-latch type threaded connection, or a
standard threaded connection. In a preferred embodiment, the second lower
sealing head 2750 is removably coupled to the load mandrel 2760 by a standard
threaded connection. In a preferred embodiment, the mechanical coupling
between the second lower sealing head 2750 and the load mandrel 2760 includes
one or more sealing members 2900 for fluidicly sealing the interface between
the second lower sealing head 2750 and the load mandrel 2760. The sealing
members 2900 may comprise any number of conventional commercially
available sealing members such as, for example, o-rings, polypak seals or
metal
spring energized seals. In a preferred embodiment, the sealing members 2900
comprise polypak seals available from Parker Seals in order to optimally
provide sealing for long axial strokes.
In a preferred embodiment, the second lower sealing head 2750 includes
a throat passage 2905 fluidicly coupled between the fluid passages 2810 and
2815. The throat passage 2905 is preferably of reduced size and is adapted to
receive and engage with a plug 2910, or other similar device. In this manner,
the fluid passage 2810 is fluidicly isolated from the fluid passage 2815. In
this
manner, the pressure chambers 2915 and 2920 are pressurized. The use of a
plurality of pressure chambers in the apparatus 2700 permits the effective
driving force to be multiplied. While illustrated using a pair of pressure
chambers, 2915 and 2920, the apparatus 2700 may be further modified to
employ additional pressure chambers.
The second outer sealing mandrel 2755 is coupled to the first upper
sealing head 2725, the first outer sealing mandrel 2735, the second upper
sealing head 2745, and the expansion cone 2765. The second outer sealing
mandrel 2755 is also movably coupled to the inner surface of the casing 2790
and the outer surface of the second lower sealing head 2750. In this manner,
the first upper sealing head 2725, first outer sealing mandrel 2735, second
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upper sealing head 2745, second outer sealing mandrel 2755, and the expansion
cone 2765 reciprocate in the axial direction.
The radial clearance between the outer surface of the second outer
sealing mandrel 2755 and the inner surface of the casing 2790 may range, for
example, from about 0.025 to 0.375 inches. In a preferred embodiment, the
radial clearance between the outer surface of the second outer sealing mandrel
2755 and the inner surface of the casing 2790 ranges from about 0.025 to 0.125
inches in order to optimally provide stabilization for the expansion cone 2765
during the expansion process. The radial clearance between the inner surface
of the second outer sealing mandrel 2755 and the outer surface of the second
lower sealing head 2750 may range, for example, from about 0.0025 to 0.05
inches. In a preferred embodiment, the radial clearance between the inner
surface of the second outer sealing mandrel 2755 and the outer surface of the
second lower sealing head 2750 ranges from about 0.005 to 0.01 inches in order
to optimally provide minimal radial clearance.
The second outer sealing mandrel 2755 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The second
outer sealing mandrel 2755 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the second outer sealing mandrel 2755 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The second outer sealing mandrel 2755 may be coupled to the second
upper sealing head 2745 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty threaded connection, ratchet-latch
type
threaded connection or a standard threaded connection. In a preferred
embodiment, the second outer sealing mandrel 2755 is removably coupled to the
second upper sealing head 2745 by a standard threaded connection. The second
outer sealing mandrel 2755 may be coupled to the expansion cone 2765 using
any number of conventional commercially available mechanical couplings such
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as, for example, drillpipe connection, oilfield country tubular goods
specialty
type threaded connection, ratchet-latch type threaded connection, or a
standard
threaded connection. In a preferred embodiment, the second outer sealing
mandrel 2755 is removably coupled to the expansion cone 2765 by a standard
threaded connection.
The load mandrel 2760 is coupled to the second lower sealing head 2750
and the mechanical slip body 2755. The load mandrel 2760 preferably
comprises an annular member having substantially cylindrical inner and outer
surfaces. The load mandrel 2760 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other
similar high strength materials. In a preferred embodiment, the load mandrel
2760 is fabricated from stainless steel in order to optimally provide high
strength, corrosion resistance, and low friction surfaces.
The load mandrel 2760 may be coupled to the second lower sealing head
2750 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, ratchet-latch type threaded
connection, or a standard threaded connection. In a preferred embodiment, the
load mandrel 2760 is removably coupled to the second lower sealing head 2750
by a standard threaded connection. The load mandrel 2760 may be coupled to
the mechanical slip body 2775 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty type threaded connection, ratchet-
latch
type threaded connection or a standard threaded connection. In a preferred
embodiment, the load mandrel 2760 is removably coupled to the mechanical slip
body 2775 by a standard threaded connection.
The load mandrel 2760 preferably includes a fluid passage 2815 that is
adapted to convey fluidic materials from the fluid passage 2810 to the fluid
passage 2820. In a preferred embodiment, the fluid passage 2815 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
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mud or lubricants at operating pressures and flow rates ranging from about 0
to
9,000 psi and 0 to 3,000 gallons/minute.
The expansion cone 2765 is coupled to the second outer sealing mandrel
2755. The expansion cone 2765 is also movably coupled to the inner surface of
the casing 2790. In this manner, the first upper sealing head 2725, first
outer
sealing mandrel 2735, second upper sealing head 2745, second outer sealing
mandrel 2755, and the expansion cone 2765 reciprocate in the axial direction.
The reciprocation of the expansion cone 2765 causes the casing 2790 to expand
in the radial direction.
The expansion cone 2765 preferably comprises an annular member
having substantially cylindrical inner and conical outer surfaces. The outside
radius of the outside conical surface may range, for example, from about 2 to
34
inches. In a preferred embodiment, the outside radius of the outside conical
surface ranges from about 3 to 28 inches in order to optimally provide
expansion cone dimensions that accommodate the typical range of casings. The
axial length of the expansion cone 2765 may range, for example, from about 2
to
8 times the largest outer diameter of the expansion cone 2765. In a preferred
embodiment, the axial length of the expansion cone 2765 ranges from about 3
to 5 times the largest outer diameter of the expansion cone 2765 in order to
optimally provide stabilization and centralization of the expansion cone 2765.
In a preferred embodiment, the angle of attack of the expansion cone 2765
ranges from about 5 to 30 degrees in order to optimally balance frictional
forces
and radial expansion forces.
The expansion cone 2765 may be fabricated from any number of
conventional commercially available materials such as, for example, machine
tool steel, nitride steel, titanium, tungsten carbide, ceramics or other
similar
high strength materials. In a preferred embodiment, the expansion cone 2765
is fabricated from D2 machine tool steel in order to optimally provide high
strength and resistance to corrosion and galling. In a particularly preferred
embodiment, the outside surface of the expansion cone 2765 has a surface
hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
high strength and resistance to wear and galling.
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The expansion cone 2765 may be coupled to the second outside sealing
mandrel 2765 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
countr~~
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
expansion cone 2765 is coupled to the second outside sealing mandrel 2765
using a standard threaded connection in order to optimally provide high
strength and easy replacement of the expansion cone 2765.
The mandrel launcher 2770 is coupled to the casing 2790. The mandrel
launcher 2770 comprises a tubular section of casing having a reduced wall
thickness compared to the casing 2790. In a preferred embodiment, the wall
thickness of the mandrel launcher 2770 is about 50 to 100 % of the wall
thickness of the casing 2790. The wall thickness of the mandrel launcher 2770
may range , for example, from about 0.15 to 1.5 inches. In a preferred
embodiment, the wall thickness of the mandrel launcher 2770 ranges from
about 0.25 to 0.75 inches. In this manner, the initiation of the radial
expansion
of the casing 2790 is facilitated, the placement of the apparatus 2700 within
a
wellbore casing and wellbore is facilitated, and the mandrel launcher 2770 has
a
burst strength approximately equal to that of the casing 2790.
The mandrel launcher 2770 may be coupled to the casing 2790 using any
number of conventional mechanical couplings such as, for example, a standard
threaded connection. The mandrel launcher 2770 may be fabricated from any
number of conventional commercially available materials such as, for example,
oilfield country tubular goods, low alloy steel, carbon steel, stainless
steel, or
other similar high strength materials. In a preferred embodiment, the mandrel
launcher 2770 is fabricated from oilfield country tubular goods of higher
strength than that of the casing 2790 but with a reduced wall thickness in
order
to optimally provide a small compact tubular container having a burst strength
approximately equal to that of the casing 2790.
The mechanical slip body 2775 is coupled to the load mandrel 2760, the
mechanical slips 2780, and the drag blocks 2785. The mechanical slip body
2775 preferably comprises a tubular member having an inner passage 2820
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fluidicly coupled to the passage 2815. In this manner, fluidic materials may
be
conveyed from the passage 2820 to a region outside of the apparatus 2700.
The mechanical slip body 2775 may be coupled to the load mandrel 2760
using any number of conventional mechanical couplings. In a preferred
embodiment, the mechanical slip body 2775 is removably coupled to the load
mandrel 2760 using a standard threaded connection in order to optimally
provide high strength and easy disassembly. The mechanical slip body 2775
may be coupled to the mechanical slips 2780 using any number of conventional
mechanical couplings. In a preferred embodiment, the mechanical slip body
2755 is removably coupled to the mechanical slips 2780 using threaded
connections and sliding steel retainer rings in order to optimally provide a
high
strength attachment. The mechanical slip body 2755 may be coupled to the
drag blocks 2785 using any number of conventional mechanical couplings. In a
preferred embodiment, the mechanical slip body 2775 is removably coupled to
the drag blocks 2785 using threaded connections and sliding steel retainer
rings
in order to optimally provide a high strength attachment.
The mechanical slip body 2775 preferably includes a fluid passage 2820
that is adapted to convey fluidic materials from the fluid passage 2815 to the
region outside of the apparatus 2700. In a preferred embodiment, the fluid
passage 2820 is adapted to convey fluidic materials such as, for example,
cement, epoxy, water, drilling mud or lubricants at operating pressures and
flow rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The mechanical slips 2780 are coupled to the outside surface of the
mechanical slip body 2775. During operation of the apparatus 2700, the
mechanical slips 2780 prevent upward movement of the casing 2790 and
mandrel launcher 2770. In this manner, during the axial reciprocation of the
expansion cone 2765, the casing 2790 and mandrel launcher 2770 are
maintained in a substantially stationary position. In this manner, the mandrel
launcher 2765 and casing 2790 and mandrel launcher 2770 are expanded in the
radial direction by the axial movement of the expansion cone 2765.
The mechanical slips 2780 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer
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tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or
Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In a
preferred embodiment, the mechanical slips 2780 comprise RTTS packer
tungsten carbide mechanical slips available from Halliburton Energy Services
in order to optimally provide resistance to axial movement of the casing 2790
and mandrel launcher 2770 during the expansion process.
The drag blocks 2785 are coupled to the outside surface of the mechanical
slip body 2775. During operation of the apparatus 2700, the drag blocks 2785
prevent upward movement of the casing 2790 and mandrel launcher 2770. In
this manner, during the axial reciprocation of the expansion cone 2765, the
casing 2790 and mandrel launcher 2770 are maintained in a substantially
stationary position. In this manner, the mandrel launcher 2770 and casing
2790 are expanded in the radial direction by the axial movement of the
expansion cone 2765.
The drag blocks 2785 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer
mechanical drag blocks or Model 3L retrievable bridge plug drag blocks. In a
preferred embodiment, the drag blocks 2785 comprise RTTS packer mechanical
drag blocks available from Halliburton Energy Services in order to optimally
provide resistance to axial movement of the casing 2790 and mandrel launcher
2770 during the expansion process.
The casing 2790 is coupled to the mandrel launcher 2770. The casing
2790 is further removably coupled to the mechanical slips 2780 and drag blocks
2785. The casing 2790 preferably comprises a tubular member. The casing
2790 may be fabricated from any number of conventional commercially
available materials such as, for example, slotted tubulars, oilfield country
tubular goods, low alloy steel, carbon steel, stainless steel or other similar
high
strength materials. In a preferred embodiment, the casing 2790 is fabricated
from oilfield country tubular goods available from various foreign and
domestic
steel mills in order to optimally provide high strength using standardized
materials. In a preferred embodiment, the upper end of the casing 2790
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includes one or more sealing members positioned about the exterior of the
casing 2790.
During operation, the apparatus 2700 is positioned in a wellbore with the
upper end of the casing 2790 positioned in an overlapping relationship within
an existing wellbore casing. In order minimize surge pressures within the
borehole during placement of the apparatus 2700, the fluid passage 2795 is
preferably provided with one or more pressure relief passages. During the
placement of the apparatus 2700 in the wellbore, the casing 2790 is supported
by the expansion cone 2765.
After positioning of the apparatus 2?00 within the bore hole in an
overlapping relationship with an existing section of wellbore casing, a first
fluidic material is pumped into the fluid passage 2795 from a surface
location.
The first fluidic material is conveyed from the fluid passage 2795 to the
fluid
passages 2800, 2802, 2805, 2810, 2815, and 2820. The first fluidic material
will
then exit the apparatus 2700 and fill the annular region between the outside
of
the apparatus 2700 and the interior walls of the bore hole.
The first fluidic material may comprise any number of conventional
commercially available materials such as, for example, epoxy, drilling mud,
slag
mix, water or cement. In a preferred embodiment, the first fluidic material
comprises a hardenable fluidic sealing material such as, for example, slag
mix,
epoxy, or cement. In this manner, a wellbore casing having an outer annular
layer of a hardenable material may be formed.
The first fluidic material may be pumped into the apparatus 2700 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi and 0 to 3,000 gallons/minute. In a preferred embodiment, the first
fluidic
material is pumped into the apparatus 2700 at operating pressures and flow
rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order
to optimally provide operational efficiency.
At a predetermined point in the injection of the first fluidic material such
as, for example, after the annular region outside of the apparatus 2700 has
been
filled to a predetermined level, a plug 2910, dart, or other similar device is
introduced into the first fluidic material. The plug 2910 lodges in the throat
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passage 2905 thereby fluidicly isolating the fluid passage 2810 from the fluid
passage 2815.
After placement of the plug 2910 in the throat passage 2905, a second
fluidic material is pumped into the fluid passage 2795 in order to pressurize
the
pressure chambers 2915 and 2920. The second fluidic material may comprise
any number of conventional commercially available materials such as, for
example, water, drilling gases, drilling mud or lubricants. In a preferred
embodiment, the second fluidic material comprises a non-hardenable fluidic
material such as, for example, water, drilling mud or lubricant. The use of
lubricant optimally provides lubrication of the moving parts of the apparatus
2700.
The second fluidic material may be pumped into the apparatus 2700 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi and 0 to 4,500 gallons/minute. In a preferred embodiment, the second
fluidic material is pumped into the apparatus 2700 at operating pressures and
flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in
order to optimally provide operational efficiency.
The pressurization of the pressure chambers 2915 and 2920 cause the
upper sealing heads, 2725 and 2745, outer sealing mandrels, 2735 and 2755,
and expansion cone 2765 to move in an axial direction. As the expansion cone
2765 moves in the axial direction, the expansion cone 2765 pulls the mandrel
launcher 2770, casing 2790, and drag blocks 2785 along, which sets the
mechanical slips 2780 and stops further axial movement of the mandrel
launcher 2770 and casing 2790. In this manner, the axial movement of the
expansion cone 2765 radially expands the mandrel launcher 2770 and casing
2790.
Once the upper sealing heads, 2725 and 2745, outer sealing mandrels,
2735 and 2755, and expansion cone 2765 complete an axial stroke, the operating
pressure of the second fluidic material is reduced and the drill string 2705
is
raised. This causes the inner sealing mandrels, 2720 and 2740, lower sealing
heads, 2730 and 2750, load mandrel 2760, and mechanical slip body 2755 to
move upward. This unsets the mechanical slips 2780 and permits the
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mechanical slips 2780 and drag blocks 2785 to be moved upward within the
mandrel launcher 2770 and casing 2790. When the lower sealing heads, 2730
and 2750, contact the upper sealing heads, 2725 and 2745, the second fluidic
material is again pressurized and the radial expansion process continues. In
this manner, the mandrel launcher 2770 and casing 2790 are radially expanded
through repeated axial strokes of the upper sealing heads, 2725 and 2745,
outer
sealing mandrels, 2735 and 2755, and expansion cone 2765. Throughout the
radial expansion process, the upper end of the casing 2790 is preferably
maintained in an overlapping relation with an existing section of wellbore
casing.
At the end of the radial expansion process, the upper end of the casing
2790 is expanded into intimate contact with the inside surface of the lower
end
of the existing wellbore casing. In a preferred embodiment, the sealing
members provided at the upper end of the casing 2790 provide a fluidic seal
between the outside surface of the upper end of the casing 2790 and the inside
surface of the lower end of the existing wellbore casing. In a preferred
embodiment, the contact pressure between the casing 2790 and the existing
section of wellbore casing ranges from about 400 to 10,000 in order to
optimally
provide contact pressure for activating the sealing members, provide optimal
resistance to axial movement of the expanded casing, and optimally resist
typical tensile and compressive loads on the expanded casing.
In a preferred embodiment, as the expansion cone 2765 nears the end of
the casing 2790, the operating pressure of the second fluidic material is
reduced
in order to minimize shock to the apparatus 2700. In an alternative
embodiment, the apparatus 2700 includes a shock absorber for absorbing the
shock created by the completion of the radial expansion of the casing 2790.
In a preferred embodiment, the reduced operating pressure of the second
fluidic material ranges from about 100 to 1,000 psi as the expansion cone 2765
nears the end of the casing 2790 in order to optimally provide reduced axial
movement and velocity of the expansion cone 2765. In a preferred embodiment,
the operating pressure of the second fluidic material is reduced during the
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return stroke of the apparatus 2700 to the range of about 0 to 500 psi in
order
minimize the resistance to the movement of the expansion cone 2765 during the
return stroke. In a preferred embodiment, the stroke length of the apparatus
2700 ranges from about 10 to 45 feet in order to optimally provide equipment
that can be easily handled by typical oil well rigging equipment and minimize
the frequency at which the apparatus 2700 must be re-stroked during an
expansion operation.
In an alternative embodiment, at least a portion of the upper sealing
heads, 2725 and 2745, include expansion cones for radially expanding the
mandrel launcher 2770 and casing 2790 during operation of the apparatus 2700
in order to increase the surface area of the casing 2790 acted upon during the
radial expansion process. In this manner, the operating pressures can be
reduced.
In an alternative embodiment, mechanical slips are positioned in an axial
location between the sealing sleeve 1915 and the first inner sealing mandrel
2720 in order to optimally provide a simplified assembly and operation of the
apparatus 2700.
Upon the complete radial expansion of the casing 2790, if applicable, the
first fluidic material is permitted to cure within the annular region between
the
outside of the expanded casing 2790 and the interior walls of the wellbore. In
the case where the casing 2790 is slotted, the cured fluidic material
preferably
permeates and envelops the expanded casing 2790. In this manner, a new
section of wellbore casing is formed within a wellbore. Alternatively, the
apparatus 2700 may be used to join a first section of pipeline to an existing
section of pipeline. Alternatively, the apparatus 2700 may be used to directly
line the interior of a wellbore with a casing, without the use of an outer
annular
layer of a hardenable material. Alternatively, the apparatus 2700 may be used
to expand a tubular support member in a hole.
During the radial expansion process, the pressurized areas of the
apparatus 2700 are limited to the fluid passages 2795, 2800, 2802, 2805, and
2810, and the pressure chambers 2915 and 2920. No fluid pressure acts directly
on the mandrel launcher 2770 and casing 2790. This permits the use of
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operating pressures higher than the mandrel launcher 2770 and casing 2790
could normally withstand.
Referring now to Figure 20, a preferred embodiment of an apparatus
3000 for forming a mono-diameter wellbore casing will be described. The
apparatus 3000 preferably includes a drillpipe 3005, an innerstring adapter
3010, a sealing sleeve 3015, a first inner sealing mandrel 3020, hydraulic
slips
3025, a first upper sealing head 3030, a first lower sealing head 3035, a
first
outer sealing mandrel 3040, a second inner sealing mandrel 3045, a second
upper sealing head 3050, a second lower sealing head 3055, a second outer
sealing mandrel 3060, load mandrel 3065, expansion cone 3070, casing 3075,
and fluid passages 3080, 3085, 3090, 3095, 3100, 3105, 3110, 3115 and 3120.
The drillpipe 3005 is coupled to the innerstring adapter 3010. During
operation of the apparatus 3000, the drillpipe 3005 supports the apparatus
3000. The drillpipe 3005 preferably comprises a substantially hollow tubular
member or members. The drillpipe 3005 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, low alloy steel, carbon steel, stainless steel or other
similar high strength materials. In a preferred embodiment, the drillpipe 3005
is fabricated from coiled tubing in order to faciliate the placement of the
apparatus 3000 in non-vertical wellbores. The drillpipe 3005 may be coupled to
the innerstring adapter 3010 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty threaded connection, or a standard
threaded connection. In a preferred embodiment, the drillpipe 3005 is
removably coupled to the innerstring adapter 3010 by a drillpipe connection.
The drillpipe 3005 preferably includes a fluid passage 3080 that is
adapted to convey fluidic materials from a surface location into the fluid
passage 3085. In a preferred embodiment, the fluid passage 3080 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud or lubricants at operating pressures and flow rates ranging from about 0
to
9,000 psi and 0 to 3,000 gallons/minute.
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The innerstring adapter 3010 is coupled to the drill string 3005 and the
sealing sleeve 3015. The innerstring adapter 3010 preferably comprises a
substantially hollow tubular member or members. The innerstring adapter
3010 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel, or other similar high strength
materials.
In a preferred embodiment, the innerstring adapter 3010 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces.
The innerstring adapter 3010 may be coupled to the drill string 3005
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, or a standard threaded connection. In a
preferred embodiment, the innerstring adapter 3010 is removably coupled to
the drill pipe 3005 by a drillpipe connection. The innerstring adapter 3010
may
be coupled to the sealing sleeve 3015 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty type threaded connection,
ratchet-latch type threaded connection or a standard threaded connection. In a
preferred embodiment, the innerstring adapter 3010 is removably coupled to
the sealing sleeve 3015 by a standard threaded connection.
The innerstring adapter 3010 preferably includes a fluid passage 3085
that is adapted to convey fluidic materials from the fluid passage 3080 into
the
fluid passage 3090. In a preferred embodiment, the fluid passage 3085 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud, or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The sealing sleeve 3015 is coupled to the innerstring adapter 3010 and
the first inner sealing mandrel 3020. The sealing sleeve 3015 preferably
comprises a substantially hollow tubular member or members. The sealing
sleeve 3015 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
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alloy steel, carbon steel, stainless steel or other similar high strength
materials.
In a preferred embodiment, the sealing sleeve 3015 is fabricated from
stainless
steel in order to optimally provide high strength, corrosion resistance, and
low
friction surfaces.
The sealing sleeve 3015 may be coupled to the innerstring adapter 3010
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type connection or a
standard
threaded connection. In a preferred embodiment, the sealing sleeve 3015 is
removably coupled to the innerstring adapter 3010 by a standard threaded
connection. The sealing sleeve 3015 may be coupled to the first inner sealing
mandrel 3020 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
sealing sleeve 3015 is removably coupled to the first inner sealing mandrel
3020
by a standard threaded connection.
The sealing sleeve 3015 preferably includes a fluid passage 3090 that is
adapted to convey fluidic materials from the fluid passage 3085 into the fluid
passage 3095. In a preferred embodiment, the fluid passage 3090 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud, or lubricants at operating pressures and flow rates ranging from about 0
to 9,000 psi and 0 to 3,000 gallons/minute.
The first inner sealing mandrel 3020 is coupled to the sealing sleeve
3015, the hydraulic slips 3025, and the first lower sealing head 3035. The
first
inner sealing mandrel 3020 is further movably coupled to the first upper
sealing
head 3030. The first inner sealing mandrel 3020 preferably comprises a
substantially hollow tubular member or members. The first inner sealing
mandrel 3020 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy steel, carbon steel, stainless steel, or similar high strength
materials. In a
preferred embodiment, the first inner sealing mandrel 3020 is fabricated from
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stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces.
The first inner sealing mandrel 3020 may be coupled to the sealing sleeve
3015 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
first inner sealing mandrel 3020 is removably coupled to the sealing sleeve
3015
by a standard threaded connection. The first inner sealing mandrel 3020 may
be coupled to the hydraulic slips 3025 using any number of conventional
commercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty type threaded connection,
ratchet-latch type threaded connection or a standard threaded connection. In a
preferred embodiment, the first inner sealing mandrel 3020 is removably
coupled to the hydraulic slips 3025 by a standard threaded connection. The
first inner sealing mandrel 3020 may be coupled to the first lower sealing
head
3035 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
first inner sealing mandrel 3020 is removably coupled to the first lower
sealing
head 3035 by a standard threaded connection.
The first inner sealing mandrel 3020 preferably includes a fluid passage
3095 that is adapted to convey fluidic materials from the fluid passage 3090
into
the fluid passage 3100. In a preferred embodiment, the fluid passage 3095 is
adapted to convey fluidic materials such as, for example, water, drilling mud,
cement, epoxy, or lubricants at operating pressures and flow rates ranging
from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The first inner sealing mandrel 3020 further preferably includes fluid
passages 3110 that are adapted to convey fluidic materials from the fluid
passage 3095 into the pressure chambers of the hydraulic slips 3025. In this
manner, the slips 3025 are activated upon the pressurization of the fluid
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passage 3095 into contact with the inside surface of the casing 3075. In a
preferred embodiment, the fluid passages 3110 are adapted to convey fluidic
materials such as, for example, cement, epoxy, water, drilling fluids or
lubricants at operating pressures and flow rates ranging from about 0 to 9,000
psi and 0 to 3,000 gallons/minute.
The first inner sealing mandrel 3020 further preferably includes fluid
passages 3115 that are adapted to convey fluidic materials from the fluid
passage 3095 into the first pressure chamber 3175 defined by the first upper
sealing head 3030, the first lower sealing head 3035, the first inner sealing
mandrel 3020, and the first outer sealing mandrel 3040. During operation of
the apparatus 3000, pressurization of the pressure chamber 3175 causes the
first upper sealing head 3030, the first outer sealing mandrel 3040, the
second
upper sealing head 3050, the second outer sealing mandrel 3060, and the
expansion cone 3070 to move in an axial direction.
The slips 3025 are coupled to the outside surface of the first inner sealing
mandrel 3020. During operation of the apparatus 3000, the slips 3025 are
activated upon the pressurization of the fluid passage 3095 into contact with
the
inside surface of the casing 3075. In this manner, the slips 3025 maintain the
casing 3075 in a substantially stationary position.
The slips 3025 preferably include fluid passages 3125, pressure chambers
3130, spring bias 3135, and slip members 3140. The slips 3025 may comprise
any number of conventional commercially available hydraulic slips such as, for
example, RTTS packer tungsten carbide hydraulic slips or Model 3L retrievable
bridge plug with hydraulic slips. In a preferred embodiment, the slips 3025
comprise RTTS packer tungsten carbide hydraulic slips available from
Halliburton Energy Services in order to optimally provide resistance to axial
movement of the casing 3075 during the expansion process. The first
upper sealing head 3030 is coupled to the first outer sealing mandrel 3040,
the
second upper sealing head 3050, the second outer sealing mandrel 3060, and the
expansion cone 3070. The first upper sealing head 3030 is also movably coupled
to the outer surface of the first inner sealing mandrel 3020 and the inner
surface of the casing 3075. In this manner, the first upper sealing head 3030,
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the first outer sealing mandrel 3040, the second upper sealing head 3050, the
second outer sealing mandrel 3060, and the expansion cone 3070 reciprocate in
the axial direction.
The radial clearance between the inner cylindrical surface of the first
upper sealing head 3030 and the outer surface of the first inner sealing
mandrel
3020 may range, for example, from about 0.0025 to 0.05 inches. In a preferred
embodiment, the radial clearance between the inner cylindrical surface of the
first upper sealing head 3030 and the outer surface of the first inner sealing
mandrel 3020 ranges from about 0.005 to 0.01 inches in order to optimally
provide minimal radial clearance. The radial clearance between the outer
cylindrical surface of the first upper sealing head 3030 and the inner surface
of
the casing 3075 may range, for example, from about 0.025 to 0.375 inches. In a
preferred embodiment, the radial clearance between the outer cylindrical
surface of the first upper sealing head 3030 and the inner surface of the
casing
3075 ranges from about 0.025 to 0.125 inches in order to optimally provide
stabilization for the expansion cone 3070 during the expansion process.
The first upper sealing head 3030 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The first
upper sealing head 3030 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, or other similar high strength
materials. In
a preferred embodiment, the first upper sealing head 3030 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces. The inner surface of the first upper sealing head
3030
preferably includes one or more annular sealing members 3145 for sealing the
interface between the first upper sealing head 3030 and the first inner
sealing
mandrel 3020. The sealing members 3145 may comprise any number of
conventional commercially available annular sealing members such as, for
example, o-rings, polypak seals or metal spring energized seals. In a
preferred
embodiment, the sealing members 3145 comprise polypak seals available from
Parker seals in order to optimally provide sealing for a long axial stroke.
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In a preferred embodiment, the first upper sealing head 3030 includes a
shoulder 3150 for supporting the first upper sealing head 3030, first outer
sealing mandrel 3040, second upper sealing head 3050, second outer sealing
mandrel 3060, and expansion cone 3070 on the first lower sealing head 3035.
The first upper sealing head 3030 may be coupled to the first outer
sealing mandrel 3040 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, or a standard threaded
connection. In a preferred embodiment, the first upper sealing head 3030 is
removably coupled to the first outer sealing mandrel 3040 by a standard
threaded connection. In a preferred embodiment, the mechanical coupling
between the first upper sealing head 3030 and the first outer sealing mandrel
3040 includes one or more sealing members 3155 for fluidicly sealing the
interface between the first upper sealing head 3030 and the first outer
sealing
mandrel 3040. The sealing members 3155 may comprise any number of
conventional commercially available sealing members such as, for example, o-
rings, polypak seals, or metal spring energized seals. In a preferred
embodiment, the sealing members 3155 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
The first lower sealing head 3035 is coupled to the first inner sealing
mandrel 3020 and the second inner sealing mandrel 3045. The first lower
sealing head 3035 is also movably coupled to the inner surface of the first
outer
sealing mandrel 3040. In this manner, the first upper sealing head 3030, first
outer sealing mandrel 3040, second upper sealing head 3050, second outer
sealing mandrel 3060, and expansion cone 3070 reciprocate in the axial
direction. The radial clearance between the outer surface of the first lower
sealing head 3035 and the inner surface of the first outer sealing mandrel
3040
may range, for example, from about 0.0025 to 0.05 inches. In a preferred
embodiment, the radial clearance between the outer surface of the first lower
sealing head 3035 and the inner surface of the outer sealing mandrel 3040
ranges from about 0.005 to 0.01 inches in order to optimally provide minimal
radial clearance.
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The first lower sealing head 3035 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The first
lower sealing head 3035 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the first lower sealing head 3035 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The outer surface of the
first
lower sealing head 3035 preferably includes one or more annular sealing
members 3160 for sealing the interface between the first lower sealing head
3035 and the first outer sealing mandrel 3040. The sealing members 3160 may
comprise any number of conventional commercially available annular sealing
members such as, for example, o-rings, polypak seals, or metal spring
energized
seals. In a preferred embodiment, the sealing members 3160 comprise polypak
seals available from Parker Seals in order to optimally provide sealing for a
long
axial stroke.
The first lower sealing head 3035 may be coupled to the first inner
sealing mandrel 3020 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
first lower sealing head 3035 is removably coupled to the first inner sealing
mandrel 3020 by a standard threaded connection. In a preferred embodiment,
the mechanical coupling between the first lower sealing head 3035 and the
first
inner sealing mandrel 3020 includes one or more sealing members 3165 for
fluidicly sealing the interface between the first lower sealing head 3035 and
the
first inner sealing mandrel 3020. The sealing members 3165 may comprise any
number of conventional commercially available sealing members such as, for
example, o-rings, polypak seals, or metal spring energized seals. In a
preferred
embodiment, the sealing members 3165 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke
length.
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The first lower sealing head 3035 may be coupled to the second inner
sealing mandrel 3045 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
first lower sealing head 3035 is removably coupled to the second inner sealing
mandrel 3045 by a standard threaded connection. In a preferred embodiment,
the mechanical coupling between the first lower sealing head 3035 and the
second inner sealing mandrel 3045 includes one or more sealing members 3170
for fluidicly sealing the interface between the first lower sealing head 3035
and
the second inner sealing mandrel 3045. The sealing members 3170 may
comprise any number of conventional commercially available sealing members
such as, for example, o-rings, polypak seals or metal spring energized seals.
In
a preferred embodiment, the sealing members 3170 comprise polypak seals
available from Parker Seals in order to optimally provide sealing for a long
axial
stroke.
The first outer sealing mandrel 3040 is coupled to the first upper sealing
head 3030 and the second upper sealing head 3050. The first outer sealing
mandrel 3040 is also movably coupled to the inner surface of the casing 3075
and the outer surface of the first lower sealing head 3035. In this manner,
the
first upper sealing head 3030, first outer sealing mandrel 3040, second upper
sealing head 3050, second outer sealing mandrel 3060, and the expansion cone
3070 reciprocate in the axial direction. The radial clearance between the
outer
surface of the first outer sealing mandrel 3040 and the inner surface of the
casing 3075 may range, for example, from about 0.025 to 0.375 inches. In a
preferred embodiment, the radial clearance between the outer surface of the
first outer sealing mandrel 3040 and the inner surface of the casing 3075
ranges
from about 0.025 to 0.125 inches in order to optimally provide stabilization
for
the expansion cone 3070 during the expansion process. The radial clearance
between the inner surface of the first outer sealing mandrel 3040 and the
outer
surface of the first lower sealing head 3035 may range, for example, from
about
0.005 to 0.125 inches. In a preferred embodiment, the radial clearance between
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the inner surface of the first outer sealing mandrel 3040 and the outer
surface
of the first lower sealing head 3035 ranges from about 0.005 to 0.01 inches in
order to optimally provide minimal radial clearance.
The first outer sealing mandrel 3040 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The first
outer sealing mandrel 3040 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the first outer sealing mandrel 3040 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The first outer sealing mandrel 3040 may be coupled to the first upper
sealing head 3030 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
first outer sealing mandrel 3040 is removably coupled to the first upper
sealing
head 3030 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the first outer sealing mandrel 3040 and the first
upper sealing head 3030 includes one or more sealing members 3180 for sealing
the interface between the first outer sealing mandrel 3040 and the first upper
sealing head 3030. The sealing members 3180 may comprise any number of
conventional commercially available sealing members such as, for example, o-
rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 3180 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
The first outer sealing mandrel 3040 may be coupled to the second upper
sealing head 3050 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection, or a standard threaded connection. In a preferred embodiment, the
first outer sealing mandrel 3040 is removably coupled to the second upper
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sealing head 3050 by a standard threaded connection. In a preferred
embodiment, the mechanical coupling between the first outer sealing mandrel
3040 and the second upper sealing head 3050 includes one or more sealing
members 3185 for sealing the interface between the first outer sealing mandrel
3040 and the second upper sealing head 3050. The sealing members 3185 may
comprise any number of conventional commercially available sealing members
such as, for example, o-rings, polypak seals or metal spring energized seals.
In
a preferred embodiment, the sealing members 3185 comprise polypak seals
available from Parker Seals in order to optimally provide sealing for a long
axial
stroke.
The second inner sealing mandrel 3045 is coupled to the first lower
sealing head 3035 and the second lower sealing head 3055. The second inner
sealing mandrel 3045 preferably comprises a substantially hollow tubular
member or members. The second inner sealing mandrel 3045 may be fabricated
from any number of conventional commercially available materials such as, for
example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless
steel or other similar high strength materials. In a preferred embodiment, the
second inner sealing mandrel 3045 is fabricated from stainless steel in order
to
optimally provide high strength, corrosion resistance, and low friction
surfaces.
The second inner sealing mandrel 3045 may be coupled to the first lower
sealing head 3035 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
second inner sealing mandrel 3045 is removably coupled to the first lower
sealing head 3035 by a standard threaded connection. The second inner
sealing mandrel 3045 may be coupled to the second lower sealing head 3055
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty type threaded connection, ratchet-latch type connection, or a
standard
threaded connection. In a preferred embodiment, the second inner sealing
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mandrel 3045 is removably coupled to the second lower sealing head 3055 by a
standard threaded connection.
The second inner sealing mandrel 3045 preferably includes a fluid
passage 3100 that is adapted to convey fluidic materials from the fluid
passage
3095 into the fluid passage 3105. In a preferred embodiment, the fluid passage
3100 is adapted to convey fluidic materials such as, for example, cement,
epoxy,
water, drilling mud or lubricants at operating pressures and flow rates
ranging
from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The second inner sealing mandrel 3045 further preferably includes fluid
passages 3120 that are adapted to convey fluidic materials from the fluid
passage 3100 into the second pressure chamber 3190 defined by the second
upper sealing head 3050, the second lower sealing head 3055, the second inner
sealing mandrel 3045, and the second outer sealing mandrel 3060. During
operation of the apparatus 3000, pressurization of the second pressure chamber
3190 causes the first upper sealing head 3030, the first outer sealing mandrel
3040, the second upper sealing head 3050, the second outer sealing mandrel
3060, and the expansion cone 3070 to move in an axial direction.
The second upper sealing head 3050 is coupled to the first outer sealing
mandrel 3040 and the second outer sealing mandrel 3060. The second upper
sealing head 3050 is also movably coupled to the outer surface of the second
inner sealing mandrel 3045 and the inner surface of the casing 3075. In this
manner, the second upper sealing head 3050 reciprocates in the axial
direction.
The radial clearance between the inner cylindrical surface of the second upper
sealing head 3050 and the outer surface of the second inner sealing mandrel
3045 may range, for example, from about 0.0025 to 0.05 inches. In a preferred
embodiment, the radial clearance between the inner cylindrical surface of the
second upper sealing head 3050 and the outer surface of the second inner
sealing mandrel 3045 ranges from about 0.005 to 0.01 inches in order to
optimally provide minimal radial clearance. The radial clearance between the
outer cylindrical surface of the second upper sealing head 3050 and the inner
surface of the casing 3075 may range, for example, from about 0.025 to 0.375
inches. In a preferred embodiment, the radial clearance between the outer
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cylindrical surface of the second upper sealing head 3050 and the inner
surface
of the casing 3075 ranges from about 0.025 to 0.125 inches in order to
optimally
provide stabilization for the expansion cone 3070 during the expansion
process.
The second upper sealing head 3050 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The second
upper sealing head 3050 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the second upper sealing head 3050 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The inner surface of the
second
upper sealing head 3050 preferably includes one or more annular sealing
members 3195 for sealing the interface between the second upper sealing head
3050 and the second inner sealing mandrel 3045. The sealing members 3195
may comprise any number of conventional commercially available annular
sealing members such as, for example, o-rings, polypak seals or metal spring
energized seals. In a preferred embodiment, the sealing members 3195
comprise polypak seals available from Parker Seals in order to optimally
provide sealing for a long axial stroke.
In a preferred embodiment, the second upper sealing head 3050 includes
a shoulder 3200 for supporting the first upper sealing head 3030, first outer
sealing mandrel 3040, second upper sealing head 3050, second outer sealing
mandrel 3060, and expansion cone 3070 on the second lower sealing head 3055.
The second upper sealing head 3050 may be coupled to the first outer
sealing mandrel 3040 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection, or a standard threaded connection. In a preferred embodiment, the
second upper sealing head 3050 is removably coupled to the first outer sealing
mandrel 3040 by a standard threaded connection. In a preferred embodiment,
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the mechanical coupling between the second upper sealing head 3050 and the
first outer sealing mandrel 3040 includes one or more sealing members 3185 for
fluidicly sealing the interface between the second upper sealing head 3050 and
the first outer sealing mandrel 3040. The second upper sealing head 3050 may
be coupled to the second outer sealing mandrel 3060 using any number of
conventional commercially available mechanical couplings such as, for example,
drillpipe connection, oilfield country tubular goods specialty type threaded
connection, ratchet-latch type threaded connection, or a standard threaded
connection. In a preferred embodiment, the second upper sealing head 3050 is
removably coupled to the second outer sealing mandrel 3060 by a standard
threaded connection. In a preferred embodiment, the mechanical coupling
between the second upper sealing head 3050 and the second outer sealing
mandrel 3060 includes one or more sealing members 3205 for fluidicly sealing
the interface between the second upper sealing head 3050 and the second outer
sealing mandrel 3060.
The second lower sealing head 3055 is coupled to the second inner
sealing mandrel 3045 and the load mandrel 3065. The second lower sealing
head 3055 is also movably coupled to the inner surface of the second outer
sealing mandrel 3060. In this manner, the first upper sealing head 3030, first
outer sealing mandrel 3040, second upper sealing mandrel 3050, second outer
sealing mandrel 3060, and expansion cone 3070 reciprocate in the axial
direction. The radial clearance between the outer surface of the second lower
sealing head 3055 and the inner surface of the second outer sealing mandrel
3060 may range, for example, from about 0.0025 to 0.05 inches. In a preferred
embodiment, the radial clearance between the outer surface of the second lower
sealing head 3055 and the inner surface of the second outer sealing mandrel
3060 ranges from about 0.005 to 0.01 inches in order to optimally provide
minimal radial clearance.
The second lower sealing head 3055 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The second
lower sealing head 3055 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
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goods, low alloy steel, carbon steel, stainless steel, or other similar high
strength materials. In a preferred embodiment, the second lower sealing head
3055 is fabricated from stainless steel in order to optimally provide high
strength, corrosion resistance, and low friction surfaces. The outer surface
of
the second lower sealing head 3055 preferably includes one or more annular
sealing members 3210 for sealing the interface between the second lower
sealing head 3055 and the second outer sealing mandrel 3060. The sealing
members 3210 may comprise any number of conventional commercially
available annular sealing members such as, for example, o-rings, polypak
seals,
or metal spring energized seals. In a preferred embodiment, the sealing
members 3210 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for long axial strokes.
The second lower sealing head 3055 may be coupled to the second inner
sealing mandrel 3045 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, or a standard threaded
connection. In a preferred embodiment, the second lower sealing head 3055 is
removably coupled to the second inner sealing mandrel 3045 by a standard
threaded connection. In a preferred embodiment, the mechanical coupling
between the lower sealing head 3055 and the second inner sealing mandrel 3045
includes one or more sealing members 3215 for fluidicly sealing the interface
between the second lower sealing head 3055 and the second inner sealing
mandrel 3045. The sealing members 3215 may comprise any number of
conventional commercially available sealing members such as, for example, o-
rings, polypak seals or metal spring energized seals. In a preferred
embodiment, the sealing members 3215 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for long axial strokes.
The second lower sealing head 3055 may be coupled to the load mandrel
3065 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods specialty type threaded connection, or a standard threaded connection.
In a preferred embodiment, the second lower sealing head 3055 is removably
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coupled to the load mandrel 3065 by a standard threaded connection. In a
preferred embodiment, the mechanical coupling between the second lower
sealing head 3055 and the load mandrel 3065 includes one or more sealing
members 3220 for fluidicly sealing the interface between the second lower
sealing head 3055 and the load mandrel 3065. The sealing members 3220 may
comprise any number of conventional commercially available sealing members
such as, for example, o-rings, polypak seals or metal spring energized seals.
In
a preferred embodiment, the sealing members 3220 comprise polypak seals
available from Parker Seals in order to optimally provide sealing for a long
axial
stroke.
In a preferred embodiment, the second lower sealing head 3055 includes
a throat passage 3225 fluidicly coupled between the fluid passages 3100 and
3105. The throat passage 3225 is preferably of reduced size and is adapted to
receive and engage with a plug 3230, or other similar device. In this manner,
the fluid passage 3100 is fluidicly isolated from the fluid passage 3105. In
this
manner, the pressure chambers 3175 and 3190 are pressurized. Furthermore,
the placement of the plug 3230 in the throat passage 3225 also pressurizes the
pressure chambers 3130 of the hydraulic slips 3025.
The second outer sealing mandrel 3060 is coupled to the second upper
sealing head 3050 and the expansion cone 3070. The second outer sealing
mandrel 3060 is also movably coupled to the inner surface of the casing 3075
and the outer surface of the second lower sealing head 3055. In this manner,
the first upper sealing head 3030, first outer sealing mandrel 3040, second
upper sealing head 3050, second outer sealing mandrel 3060, and the expansion
cone 3070 reciprocate in the axial direction. The radial clearance between the
outer surface of the second outer sealing mandrel 3060 and the inner surface
of
the casing 3075 may range, for example, from about 0.025 to 0.375 inches. In a
preferred embodiment, the radial clearance between the outer surface of the
second outer sealing mandrel 3060 and the inner surface of the casing 3075
ranges from about 0.025 to 0.125 inches in order to optimally provide
stabilization for the expansion cone 3070 during the expansion process. The
radial clearance between the inner surface of the second outer sealing mandrel
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3060 and the outer surface of the second lower sealing head 3055 may range,
for
example, from about 0.0025 to 0.05 inches. In a preferred embodiment, the
radial clearance between the inner surface of the second outer sealing mandrel
3060 and the outer surface of the second lower sealing head 3055 ranges from
about 0.005 to 0.01 inches in order to optimally provide minimal radial
clearance.
The second outer sealing mandrel 3060 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The second
outer sealing mandrel 3060 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the second outer sealing mandrel 3060 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The second outer sealing mandrel 3060 may be coupled to the second
upper sealing head 3050 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty type threaded connection, or a
standard
threaded connection. In a preferred embodiment, the outer sealing mandrel
3060 is removably coupled to the second upper sealing head 3050 by a standard
threaded connection. The second outer sealing mandrel 3060 may be coupled to
the expansion cone 3070 using any number of conventional commercially
available mechanical couplings such as, for example, drillpipe connection,
oilfield country tubular goods specialty type threaded connection, or a
standard
threaded connection. In a preferred embodiment, the second outer sealing
mandrel 3060 is removably coupled to the expansion cone 3070 by a standard
threaded connection.
The first upper sealing head 3030, the first lower sealing head 3035, the
first inner sealing mandrel 3020, and the first outer sealing mandrel 3040
together define the first pressure chamber 3175. The second upper sealing head
3050, the second lower sealing head 3055, the second inner sealing mandrel
3045, and the second outer sealing mandrel 3060 together define the second
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CA 02299076 2000-02-22
pressure chamber 3190. The first and second pressure chambers, 3175 and
3190, are fluidicly coupled to the passages, 3095 and 3100, via one or mor
a
passages, 3115 and 3120. During operation of the apparatus 3000, the plug
3230 engages with the throat passage 3225 to fluidicly isolate the fluid a
p ssage
3100 from the fluid passage 3105. The pressure chambers, 3175 and 31
90, are
then pressurized which in turn causes the first upper sealing head 3030 the
first outer sealing mandrel 3040, the second upper sealing head 3050 the
second outer sealing mandrel 3060, and a
xpansion cone 3070 to reciprocate in
the axial direction. The axial motion of the expansion cone 3070 in turn
expands the casing 3075 in the radial direction. The use of a plurali of
ty
pressure chambers, 31?5 and 3190, effectively multiplies the available drivin
g
force for the expansion cone 3070.
The load mandrel 3065 is coupled to the second lower sealing head 3055.
The load mandrel 3065 preferably comprises an annular member havin
g
substantially cylindrical inner and outer surfaces. The load mandrel 3065
may
be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, low alloy
steel,
carbon steel, stainless steel or other similar high strength materials. In a
preferred embodiment, the load mandrel 3065 is fabricated from stainless steel
in order to optimally provide high strength, corrosion resistance, and low
friction surfaces.
The load mandrel 3065 may be coupled to the lower sealing head 3055
using any number of conventional commercially available mechanical cou lin s
P g
such as, for example, epoxy, cement, water, drilling mud, or lubricants. In a
preferred embodiment, the load mandrel 3065 is removably coupled to the 1
ower
sealing head 3055 by a standard threaded connection.
The load mandrel 3065 preferably includes a fluid passage 3105 that is
adapted to convey fluidic materials from the fluid passage 3100 to the re 'on
l~
outside of the apparatus 3000. .In a preferred embodiment, the fluid passage
3105 is adapted to convey fluidic materials such as, for example, cement a
poxy,
water, drilling mud or lubricants at operating pressures and flow rates
ranging
from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
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The expansion cone 3070 is coupled to the second outer sealing mandrel
3060. The expansion cone 3070 is also movably coupled to the inner surface of
the casing 3075. In this manner, the first upper sealing head 3030, first
outer
sealing mandrel 3040, second upper sealing head 3050, second outer sealing
mandrel 3060, and the expansion cone 3070 reciprocate in the axial direction.
The reciprocation of the expansion cone 3070 causes the casing 3075 to expand
in the radial direction.
The expansion cone 3070 preferably comprises an annular member
having substantially cylindrical inner and conical outer surfaces. The outside
radius of the outside conical surface may range, for example, from about 2 to
34
inches. In a preferred embodiment, the outside radius of the outside conical
surface ranges from about 3 to 28 inches in order to optimally provide an
expansion cone 3070 for expanding typical casings. The axial length of the
expansion cone 3070 may range, for example, from about 2 to 8 times the
maximum outer diameter of the expansion cone 3070. In a preferred
embodiment, the axial length of the expansion cone 3070 ranges from about 3
to 5 times the maximum outer diameter of the expansion cone 3070 in order to
optimally provide stabilization and centralization of the expansion cone 3070
.
during the expansion process. In a particularly preferred embodiment, the
maximum outside diameter of the expansion cone 3070 is between about 95 to
99 % of the inside diameter of the existing wellbore that the casing 3075 will
be
joined with. In a preferred embodiment, the angle of attack of the expansion
cone 3070 ranges from about 5 to 30 degrees in order to optimally balance the
frictional forces with the radial expansion forces.
The expansion cone 3070 may be fabricated from any number of
conventional commercially available materials such as, for example, machine
tool steel, nitride steel, titanium, tungsten carbide, ceramics, or other
similar
high strength materials. In a preferred embodiment, the expansion cone 3070
is fabricated from D2 machine tool steel in order to optimally provide high
strength and resistance to wear and galling. In a particularly preferred
embodiment, the outside surface of the expansion cone 3070 has a surface
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hardness ranging from about 58 to 62 Rockwell C in order to optimally provide
high strength and resistance to wear and galling.
The expansion cone 3070 may be coupled to the second outside sealing
mandrel 3060 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type
connection
or a standard threaded connection. In a preferred embodiment; the expansion
cone 3070 is coupled to the second outside sealing mandrel 3060 using a
standard threaded connection in order to optimally provide high strength and
easy disassembly.
The casing 3075 is removably coupled to the slips 3025 and the expansion
cone 3070. The casing 3075 preferably comprises a tubular member. The
casing 3075 may be fabricated from any number of conventional commercially
available materials such as, for example, slotted tubulars, oilfield country
tubular goods, carbon steel, low alloy steel, stainless steel, or other
similar high
strength materials. In a preferred embodiment, the casing 3075 is fabricated
from oilfield country tubular goods available from various foreign and
domestic
steel mills in order to optimally provide high strength.
In a preferred embodiment, the upper end 3235 of the casing 3075
includes a thin wall section 3240 and an outer annular sealing member 3245.
In a preferred embodiment, the wall thickness of the thin wall section 3240 is
about 50 to 100 % of the regular wall thickness of the casing 3075. In this
manner, the upper end 3235 of the casing 3075 may be easily radially expanded
and deformed into intimate contact with the lower end of an existing section
of
wellbore casing. In a preferred embodiment, the lower end of the existing
section of casing also includes a thin wall section. In this manner, the
radial
expansion of the thin walled section 3240 of casing 3075 into the thin walled
section of the existing wellbore casing results in a wellbore casing having a
substantially constant inside diameter.
The annular sealing member 3245 may be fabricated from any number of
conventional commercially available sealing materials such as, for example,
epoxy, rubber, metal or plastic. In a preferred embodiment, the annular
sealing
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member 3245 is fabricated from StrataLock epoxy in order to optimally provide
compressibility and wear resistance. The outside diameter of the annular
sealing member 3245 preferably ranges from about 70 to 95 % of the inside
diameter of the lower section of the wellbore casing that the casing 3075 is
joined to. In this manner, after radial expansion, the annular sealing member
3245 optimally provides a fluidic seal and also preferably optimally provides
sufficient frictional force with the inside surface of the existing section of
wellbore casing during the radial expansion of the casing 3075 to support the
casing 3075.
In a preferred embodiment, the lower end 3250 of the casing 3075
includes a thin wall section 3255 and an outer annular sealing member 3260.
In a preferred embodiment, the wall thickness of the thin wall section 3255 is
about 50 to 100 % of the regular wall thickness of the casing 3075. In this
manner, the lower end 3250 of the casing 3075 may be easily expanded and
deformed. Furthermore, in this manner, an other section of casing may be
easily joined with the lower end 3250 of the casing 3075 using a radial
expansion process. In a preferred embodiment, the upper end of the other
section of casing also includes a thin wall section. In this manner, the
radial
expansion of the thin walled section of the upper end of the other casing into
the thin walled section 3255 of the lower end 3250 of the casing 3075 results
in
a wellbore casing having a substantially constant inside diameter.
The upper annular sealing member 3245 may be fabricated from any
number of conventional commercially available sealing materials such as, for
example, epoxy, rubber, metal or plastic. In a preferred embodiment, the upper
annular sealing member 3245 is fabricated from Stratalock epoxy in order to
optimally provide compressibility and resistance to wear. The outside diameter
of the upper annular sealing member 3245 preferably ranges from about 70 to
95 % of the inside diameter of the lower section of the existing wellbore
casing
that the casing 3075 is joined to. In this manner, after radial expansion, the
upper annular sealing member 3245 preferably provides a fluidic seal and also
preferably provides sufficient frictional force with the inside wall of the
wellbore
during the radial expansion of the casing 3075 to support the casing 3075.
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The lower annular sealing member 3260 may be fabricated from any
number of conventional commercially available sealing materials such as, for
example, epoxy, rubber, metal or plastic. In a preferred embodiment, the lower
annular sealing member 3260 is fabricated from StrataLock epoxy in order to
optimally provide compressibility and resistance to wear. The outside diameter
of the lower annular sealing member 3260 preferably ranges from about 70 to
95 % of the inside diameter of the lower section of the existing wellbore
casing
that the casing 3075 is joined to. In this manner, the lower annular sealing
member 3260 preferably provides a fluidic seal and also preferably provides
sufficient frictional force with the inside wall of the wellbore during the
radial
expansion of the casing 3075 to support the casing 3075.
During operation, the apparatus 3000 is preferably positioned in a
wellbore with the upper end 3235 of the casing 3075 positioned in an
overlapping relationship with the lower end of an existing wellbore casing. In
a
particularly preferred embodiment, the thin wall section 3240 of the casing
3075 is positioned in opposing overlapping relation with the thin wall section
and outer annular sealing member of the lower end of the existing section of
wellbore casing. In this manner, the radial expansion of the casing 3075 will
compress the thin wall sections and annular compressible members of the upper
end 3235 of the casing 3075 and the lower end of the existing wellbore casing
into intimate contact. During the positioning of the apparatus 3000 in the
wellbore, the casing 3000 is preferably supported by the expansion cone 3070.
After positioning the apparatus 3000, a first fluidic material is then
pumped into the fluid passage 3080. The first fluidic material may comprise
any number of conventional commercially available materials such as, for
example, drilling mud, water, epoxy, cement, slag mix or lubricants. In a
preferred embodiment, the first fluidic material comprises a hardenable
fluidic
sealing material such as, for example, cement, epoxy, or slag mix in order to
optimally provide a hardenable outer annular body around the expanded casing
3075.
The first fluidic material may be pumped into the fluid passage 3080 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
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psi and 0 to 4,500 gallons/minute. In a preferred embodiment, the first
fluidic
material is pumped into the fluid passage 3080 at operating pressures and flow
rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order
to optimally provide operating efficiency.
The first fluidic material pumped into the fluid passage 3080 passes
through the fluid passages 3085, 3090, 3095, 3100, and 3105 and then outside
of
the apparatus 3000. The first fluidic material then preferably fills the
annular
region between the outside of the apparatus 3000 and the interior walls of the
wellbore.
The plug 3230 is then introduced into the fluid passage 3080. The plug
3230 lodges in the throat passage 3225 and fluidicly isolates and blocks off
the
fluid passage 3100. In a preferred embodiment, a couple of volumes of a non-
hardenable fluidic material are then pumped into the fluid passage 3080 in
order to remove any hardenable fluidic material contained within and to ensure
that none of the fluid passages are blocked.
A second fluidic material is then pumped into the fluid passage 3080.
The second fluidic material may comprise any number of conventional
commercially available materials such as, for example, water, drilling gases,
drilling mud or lubricant. In a preferred embodiment, the second fluidic
material comprises a non-hardenable fluidic material such as, for example,
water, drilling mud, drilling gases, or lubricant in order to optimally
provide
pressurization of the pressure chambers 3175 and 3190.
The second fluidic material may be pumped into the fluid passage 3080 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi and 0 to 4,500 gallons/minute. In a preferred embodiment, the second
fluidic material is pumped into the fluid passage 3080 at operating pressures
and flow rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute
in order to optimally provide operational efficiency.
The second fluidic material pumped into the fluid passage 3080 passes
through the fluid passages 3085, 3090, 3095, 3100 and into the pressure
chambers 3130 of the slips 3025, and into the pressure chambers 3175 and
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3190. Continued pumping of the second fluidic material pressurizes the
pressure chambers 3130, 3175, and 3190.
The pressurization of the pressure chambers 3130 causes the hydraulic
slip members 3140 to expand in the radial direction and grip the interior
surface of the casing 3075. The casing 3075 is then preferably maintained in a
substantially stationary position.
The pressurization of the pressure chambers 3175 and 3190 cause the
first upper sealing head 3030, first outer sealing mandrel 3040, second upper
sealing head 3050, second outer sealing mandrel 3060, and expansion cone 3070
to move in an axial direction relative to the casing 3075. In this manner, the
expansion cone 3070 will cause the casing 3075 to expand in the radial
direction, beginning with the lower end 3250 of the casing 3075.
During the radial expansion process, the casing 3075 is prevented from
moving in an upward direction by the slips 3025. A length of the casing 3075
is
then expanded in the radial direction through the pressurization of the
pressure
chambers 3175 and 3190. The length of the casing 3075 that is expanded
during the expansion process will be proportional to the stroke length of the
first upper sealing head 3030, first outer sealing mandrel 3040, second upper
sealing head 3050, and expansion cone 3070.
Upon the completion of a stroke, the operating pressure of the second
fluidic material is reduced and the first upper sealing head 3030, first outer
sealing mandrel 3040, second upper sealing head 3050, second outer sealing
mandrel 3060, and expansion cone 3070 drop to their rest positions with the
casing 3075 supported by the expansion cone 3070. The reduction in the
operating pressure of the second fluidic material also causes the spring bias
3135 of the slips 3025 to pull the slip members 3140 away from the inside
walls
of the casing 3075.
The position of the drillpipe 3075 is preferably adjusted throughout the
radial expansion process in order to maintain the overlapping relationship
between the thin walled sections of the lower end of the existing wellbore
casing
and the upper end of the casing 3235. In a preferred embodiment, the stroking
of the expansion cone 3070 is then repeated, as necessary, until the thin
walled
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section 3240 of the upper end 3235 of the casing 3075 is expanded into the
thin
walled section of the lower end of the existing wellbore casing. In this
manner,
a wellbore casing is formed including two adjacent sections of casing having a
substantially constant inside diameter. This process may then be repeated for
the entirety of the wellbore to provide a wellbore casing thousands of feet in
length having a substantially constant inside diameter.
In a preferred embodiment, during the final stroke of the expansion cone
3070, the slips 3025 are positioned as close as possible to the thin walled
section
3240 of the upper end 3235 of the casing 3075 in order minimize slippage
between the casing 3075 and the existing wellbore casing at the end of the
radial expansion process. Alternatively, or in addition, the outside diameter
of
the upper annular sealing member 3245 is selected to ensure sufficient
interference fit with the inside diameter of the lower end of the existing
casing
to prevent axial displacement of the casing 3075 during the final stroke.
Alternatively, or in addition, the outside diameter of the lower annular
sealing
member 3260 is selected to provide an interference fit with the inside walls
of
the wellbore at an earlier point in the radial expansion process so as to
prevent
further axial displacement of the casing 3075. In this final alternative, the
interference fit is preferably selected to permit expansion of the casing 3075
by
pulling the expansion cone 3070 out of the wellbore, without having to
pressurize the pressure chambers 3175 and 3190.
During the radial expansion process, the pressurized areas of the
apparatus 3000 are preferably limited to the fluid passages 3080, 3085, 3090,
3095, 3100, 3110, 3115, 3120, the pressure chambers 3130 within the slips
3025,
and the pressure chambers 3175 and 3190. No fluid pressure acts directly on
the casing 3075. This permits the use of operating pressures higher than the
casing 3075 could normally withstand.
Once the casing 3075 has been completely expanded off of the expansion
cone 3070, the remaining portions of the apparatus 3000 are removed from the
wellbore. In a preferred embodiment, the contact pressure between the
deformed thin wall sections and compressible annular members of the lower
end of the existing casing and the upper end 3235 of the casing 3075 ranges
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from about 400 to 10,000 psi in order to optimally support the casing 3075
using the existing wellbore casing.
In this manner, the casing 3075 is radially expanded into contact with an
existing section of casing by pressurizing the interior fluid passages 3080,
3085,
3090, 3095, 3100, 3110, 3115, and 3120, the pressure chambers 3130 of the
slips
3025 and the pressure chambers 3175 and 3190 of the apparatus 3000.
In a preferred embodiment, as required, the annular body of hardenable
fluidic material is then allowed to cure to form a rigid outer annular body
about
the expanded casing 3075. In the case where the casing 3075 is slotted, the
cured fluidic material preferably permeates and envelops the expanded casing
3075. The resulting new section of wellbore casing includes the expanded
casing 3075 and the rigid outer annular body. The overlapping joint between
the pre-existing wellbore casing and the expanded casing 3075 includes the
deformed thin wall sections and the compressible outer annular bodies. The
inner diameter of the resulting combined wellbore casings is substantially
constant. In this manner, a mono-diameter wellbore casing is formed. This
process of expanding overlapping tubular members having thin wall end
portions with compressible annular bodies into contact can be repeated for the
entire length of a wellbore. In this manner, a mono-diameter wellbore casing
can be provided for thousands of feet in a subterranean formation.
In a preferred embodiment, as the expansion cone 3070 nears the upper
end 3235 of the casing 3075, the operating flow rate of the second fluidic
material is reduced in order to minimize shock to the apparatus 3000. In an
alternative embodiment, the apparatus 3000 includes a shock absorber for
absorbing the shock created by the completion of the radial expansion of the
casing 3075.
In a preferred embodiment, the reduced operating pressure of the second
fluidic material ranges from about 100 to 1,000 psi as the expansion cone 3070
nears the end of the casing 3075 in order to optimally provide reduced axial
movement and velocity of the expansion cone 3070. In a preferred embodiment,
the operating pressure of the second fluidic material is reduced during the
return stroke of the apparatus 3000 to the range of about 0 to 500 psi in
order
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minimize the resistance to the movement of the expansion cone 3070 during the
return stroke. In a preferred embodiment, the stroke length of the apparatus
3000 ranges from about 10 to 45 feet in order to optimally provide equipment
that can be easily handled by typical oil well rigging equipment and also
minimize the frequency at which the apparatus 3000 must be re-stroked.
In an alternative embodiment, at least a portion of one or both of the
upper sealing heads, 3030 and 3050, includes an expansion cone for radially
expanding the casing 3075 during operation of the apparatus 3000 in order to
increase the surface area of the casing 3075 acted upon during the radial
expansion process. In this manner, the operating pressures can be reduced.
Alternatively, the apparatus 3000 may be used to join a first section of
pipeline to an existing section of pipeline. Alternatively, the apparatus 3000
may be used to directly line the interior of a wellbore with a casing, without
the
use of an outer annular layer of a hardenable material. Alternatively, the
apparatus 3000 may be used to expand a tubular support member in a hole.
Referring now to Figure 21, an apparatus 3330 for isolating
subterranean zones will be described. A wellbore 3305 including a casing 3310
are positioned in a subterranean formation 3315. The subterranean formation
3315 includes a number of productive and non-productive zones, including a
water zone 3320 and a targeted oil sand zone 3325. During exploration of the
subterranean formation 3315, the wellbore 3305 may be extended in a well
known manner to traverse the various productive and non-productive zones,
including the water zone 3320 and the targeted oil sand zone 3325.
In a preferred embodiment, in order to fluidicly isolate the water zone
3320 from the targeted oil sand zone 3325, an apparatus 3330 is provided that
includes one or more sections of solid casing 3335, one or more external seals
3340, one or more sections of slotted casing 3345, one or more intermediate
sections of solid casing 3350, and a solid shoe 3355.
The solid casing 3335 may provide a fluid conduit that transmits fluids
and other materials from one end of the solid casing 3335 to the other end of
the solid casing 3335. The solid casing 3335 may comprise any number of
conventional commercially available sections of solid tubular casing such as,
for
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example, oilfield tubulars fabricated from chromium steel or fiberglass. In a
preferred embodiment, the solid casing 3335 comprises oilfield tubulars
available from various foreign and domestic steel mills.
The solid casing 3335 is preferably coupled to the casing 3310. The solid
casing 3335 may be coupled to the casing 3310 using any number of
conventional commercially available processes such as, for example, welding,
slotted and expandable connectors, or expandable solid connectors. In a
preferred embodiment, the solid casing 3335 is coupled to the casing 3310 by
using expandable solid connectors. The solid casing 3335 may comprise a
plurality of such solid casings 3335.
The solid casing 3335 is preferably coupled to one more of the slotted
casings 3345. The solid casing 3335 may be coupled to the slotted casing 3345
using any number of conventional commercially available processes such as, for
example, welding, or slotted and expandable connectors. In a preferred
embodiment, the solid casing 3335 is coupled to the slotted casing 3345 by
expandable solid connectors.
In a preferred embodiment, the casing 3335 includes one more valve
members 3360 for controlling the flow of fluids and other materials within the
interior region of the casing 3335. In an alternative embodiment, during the
production mode of operation, an internal tubular string with various
arrangements of packers, perforated tubing, sliding sleeves, and valves may be
employed within the apparatus to provide various options for commingling and
isolating subterranean zones from each other while providing a fluid path to
the
surface.
In a particularly preferred embodiment, the casing 3335 is placed into
the wellbore 3305 by expanding the casing 3335 in the radial direction into
intimate contact with the interior walls of the wellbore 3305. The casing 3335
may be expanded in the radial direction using any number of conventional
commercially available methods. In a preferred embodiment, the casing 3335 is
expanded in the radial direction using one or more of the processes and
apparatus described within the present disclosure.
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The seals 3340 prevent the passage of fluids and other materials within
the annular region 3365 between the solid casings 3335 and 3350 and the
wellbore 3305. The seals 3340 may comprise any number of conventional
commercially available sealing materials suitable for sealing a casing in a
wellbore such as, for example, lead, rubber or epoxy. In a preferred
embodiment, the seals 3340 comprise Stratalok epoxy material available from
Halliburton Energy Services.
The slotted casing 3345 permits fluids and other materials to pass into
and out of the interior of the slotted casing 3345 from and to the annular
region
3365. In this manner, oil and gas may be produced from a producing
subterranean zone within a subterranean formation. The slotted casing 3345
may comprise any number of conventional commercially available sections of
slotted tubular casing. In a preferred embodiment, the slotted casing 3345
comprises expandable slotted tubular casing available from Petroline in
Abeerdeen, Scotland. In a particularly preferred embodiment, the slotted
casing 145 comprises expandable slotted sandscreen tubular casing available
from Petroline in Abeerdeen, Scotland.
The slotted casing 3345 is preferably coupled to one or more solid casing
3335. The slotted casing 3345 may be coupled to the solid casing 3335 using
any number of conventional commercially available processes such as, for
example, welding, or slotted or solid expandable connectors. In a preferred
embodiment, the slotted casing 3345 is coupled to the solid casing 3335 by
expandable solid connectors.
The slotted casing 3345 is preferably coupled to one or more intermediate
solid casings 3350. The slotted casing 3345 may be coupled to the intermediate
solid casing 3350 using any number of conventional commercially available
processes such as, for example, welding or expandable solid or slotted
connectors. In a preferred embodiment, the slotted casing 3345 is coupled to
the intermediate solid casing 3350 by expandable solid connectors.
The last section of slotted casing 3345 is preferably coupled to the shoe
3355. The last slotted casing 3345 may be coupled to the shoe 3355 using any
number of conventional commercially available processes such as, for example,
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welding or expandable solid or slotted connectors. In a preferred embodiment,
the last slotted casing 3345 is coupled to the shoe 3355 by an expandable
solid
connector.
In an alternative embodiment, the shoe 3355 is coupled directly to the
last one of the intermediate solid casings 3350.
In a preferred embodiment, the slotted casings 3345 are positioned
within the wellbore 3305 by expanding the slotted casings 3345 in a radial
direction into intimate contact with the interior walls of the wellbore 3305.
The
slotted casings 3345 may be expanded in a radial direction using any number of
conventional commercially available processes. In a preferred embodiment, the
slotted casings 3345 are expanded in the radial direction using one or more of
the processes and apparatus disclosed in the present disclosure with reference
to Figures 14a-20.
The intermediate solid casing 3350 permits fluids and other materials to
pass between adjacent slotted casings 3345. The intermediate solid casing 3350
may comprise any number of conventional commercially available sections of
solid tubular casing such as, for example, oilfield tubulars fabricated from
chromium steel or fiberglass. In a preferred embodiment, the intermediate
solid casing 3350 comprises oilfield tubulars available from foreign and
domestic steel mills.
The intermediate solid casing 3350 is preferably coupled to one or more
sections of the slotted casing 3345. The intermediate solid casing 3350 may be
coupled to the slotted casing 3345 using any number of conventional
commercially available processes such as, for example, welding, or solid or
slotted expandable connectors. In a preferred embodiment, the intermediate
solid casing 3350 is coupled to the slotted casing 3345 by expandable solid
connectors. The intermediate solid casing 3350 may comprise a plurality of
such intermediate solid casing 3350.
In a preferred embodiment, each intermediate solid casing 3350 includes
one more valve members 3370 for controlling the flow of fluids and other
materials within the interior region of the intermediate casing 3350. In an
alternative embodiment, as will be recognized by persons having ordinary skill
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in the art and the benefit of the present disclosure, during the production
mode
of operation, an internal tubular string with various arrangements of packers,
perforated tubing, sliding sleeves, and valves may be employed within the
apparatus to provide various options for commingling and isolating
subterranean zones from each other while providing a fluid path to the
surface.
In a particularly preferred embodiment, the intermediate casing 3350 is
placed into the wellbore 3305 by expanding the intermediate casing 3350 in the
radial direction into intimate contact with the interior walls of the wellbore
3305. The intermediate casing 3350 may be expanded in the radial direction
using any number of conventional commercially available methods.
In an alternative embodiment, one or more of the intermediate solid
casings 3350 may be omitted. In an alternative preferred embodiment, one or
more of the slotted casings 3345 are provided with one or more seals 3340.
The shoe 3355 provides a support member for the apparatus 3330. In
this manner, various production and exploration tools may be supported by the
show 3350. The shoe 3350 may comprise any number of conventional
commercially available shoes suitable for use in a wellbore such as, for
example,
cement filled shoe, or an aluminum or composite shoe. In a preferred
embodiment, the shoe 3350 comprises an aluminum shoe available from
Halliburton. In a preferred embodiment, the shoe 3355 is selected to provide
sufficient strength in compression and tension to permit the use of high
capacity production and exploration tools.
In a particularly preferred embodiment, the apparatus 3330 includes a
plurality of solid casings 3335, a plurality of seals 3340, a plurality of
slotted
casings 3345, a plurality of intermediate solid casings 3350, and a shoe 3355.
More generally, the apparatus 3330 may comprise one or more solid casings
3335, each with one or more valve members 3360, n slotted casings 3345, n-1
intermediate solid casings 3350, each with one or more valve members 3370,
and a shoe 3355.
During operation of the apparatus 3330, oil and gas may be controllably
produced from the targeted oil sand zone 3325 using the slotted casings 3345.
The oil and gas may then be transported to a surface location using the solid
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casing 3335. The use of intermediate solid casings 3350 with valve members
3370 permits isolated sections of the zone 3325 to be selectively isolated for
production. The seals 3340 permit the zone 3325 to be fluidicly isolated from
the zone 3320. The seals 3340 further permits isolated sections of the zone
3325 to be fluidicly isolated from each other. In this manner, the apparatus
3330 permits unwanted and/or non-productive subterranean zones to be
fluidicly isolated.
In an alternative embodiment, as will be recognized by persons having
ordinary skill in the art and also having the benefit of the present
disclosure,
during the production mode of operation, an internal tubular string with
various arrangements of packers, perforated tubing, sliding sleeves, and
valves
may be employed within the apparatus to provide various options for
commingling and isolating subterranean zones from each other while providing
a fluid path to the surface.
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
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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
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 wellbore 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
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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
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
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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.
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 wellbore 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
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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
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
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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.
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.
A 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
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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
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
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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
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
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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
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
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preferred embodiment, the mandrel is supported with coiled tubing. In a
preferred embodiment, the mandrel is coupled to a drillable shoe.
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
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preferred embodiment, the inner tubular members are supported by their
contact with the outer tubular member.
A wellbore casing has also been described that includes a first tubular
member, and a second tubular member coupled to the first tubular member in
an overlapping relationship. The inner diameter of the first tubular member is
substantially equal to the inner diameter of the second tubular member. In a
preferred embodiment, the first tubular member includes a first thin wall
section, wherein the second tubular member includes a second thin wall
section,
and wherein the first thin wall section is coupled to the second thin wall
section. In a preferred embodiment, first and second thin wall sections are
deformed. In a preferred embodiment, the first tubular member includes a first
compressible member coupled to the first thin wall section, and wherein the
second tubular member includes a second compressible member coupled to the
second thin wall section. In a preferred embodiment, the first thin wall
section
and the first compressible member are coupled to the second thin wall section
and the second compressible member. In a preferred embodiment, the first
and second thin wall sections and the first and second compressible members
are deformed.
A wellbore casing has also been described that includes a tubular
member including at least one thin wall section and a thick wall section, and
a compressible annular member coupled to each thin wall section. In a
preferred embodiment, the compressible annular member is fabricated from
materials selected from the group consisting of rubber, plastic, metal and
epoxy.
In a preferred embodiment, the wall thickness of the thin wall section ranges
from about 50 to 100 % of the wall thickness of the thick wall section. In a
preferred embodiment, the length of the thin wall section ranges from about
120 to 2400 inches. In a preferred embodiment, the compressible annular
member is positioned along the thin wall section. In a preferred embodiment,
the compressible annular member is positioned along the thin and thick wall
sections. In a preferred embodiment, the tubular member is fabricated from
materials selected from the group consisting of oilfield country tubular
goods,
stainless steel, low alloy steel, carbon steel, automotive grade steel,
plastics,
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fiberglass, high strength and/or deformable materials. In a preferred
embodiment, the wellbore casing includes a first thin wall at a first end of
the
casing, and a second thin wall at a second end of the casing.
A method of creating a casing in a borehole located in a subterranean
formation has also been described that includes supporting a tubular liner and
a mandrel in the borehole using a support member, injecting fluidic material
into the borehole, pressurizing an interior region of the mandrel, displacing
a
portion of the mandrel relative to the support member, and radially expanding
the tubular liner. In a preferred embodiment, the injecting includes injecting
hardenable fluidic sealing material into an annular region located between the
borehole and the exterior of the tubular liner, and injecting non hardenable
fluidic material into an interior region of the mandrel. In a preferred
embodiment, the method further includes fluidicly isolating the annular region
from the interior region before injecting the non hardenable fluidic material
into the interior region of the mandrel. In a preferred embodiment, the
injecting of the hardenable fluidic sealing material is provided at operating
pressures and flow rates ranging from about 0 to 5,000 psi and 0 to 1,500
gallons/min. In a preferred embodiment, the injecting of the non hardenable
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 non hardenable fluidic material is provided at reduced
operating pressures and flow rates during an end portion of the radial
expansion. In a preferred embodiment, the fluidic material is injected into
one
or more pressure chambers. In a preferred embodiment, the one or more
pressure chambers are pressurized. In a preferred embodiment, the pressure
chambers are pressurized to pressures ranging from about 500 to 9,000 psi. In
a preferred embodiment, the method further includes fluidicly isolating an
interior region of the mandrel from an exterior region of the mandrel. In a
preferred embodiment, the interior region of the mandrel is isolated from the
region exterior to the mandrel by inserting one or more plugs into the
injected
fluidic material. In a preferred embodiment, the method further includes
curing at least a portion of the fluidic material, and removing at least a
portion
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of the cured fluidic material located within the tubular liner. In a preferred
embodiment, the method further includes overlapping the tubular liner with an
existing wellbore casing. In a preferred embodiment, the method further
includes sealing the overlap between the tubular liner and the existing
wellbore
casing. In a preferred embodiment, the method further includes supporting the
extruded tubular liner using the overlap with the existing wellbore casing. In
a
preferred embodiment, the method further incfle~ag the integrity of the seal
in
the overlap between the tubular liner and the existing wellbore casing. In a
preferred embodiment, the method further includes removing at least a portion
of the hardenable fluidic sealing material within the tubular liner before
curing.
In a preferred embodiment, the 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 drilling out the mandrel. In a
preferred embodiment, the method further includes supporting the mandrel
with coiled tubing. In a preferred embodiment, the mandrel reciprocates. In a
preferred embodiment, the mandrel is displaced in a first direction during the
pressurization of the interior region of the mandrel, and the mandrel is
displaced in a second direction during a de-pressurization of the interior
region
of the mandrel. In a preferred embodiment, the tubular liner is maintained in
a
substantially stationary position during the pressurization of the interior
region
of the mandrel. In a preferred embodiment, the tubular liner is supported by
the mandrel during a de-pressurization of the interior region of the mandrel.
A wellbore casing has also been described that includes a first tubular
member having a first inside diameter, and a second tubular member having a
second inside diameter substantially equal to the first inside diameter
coupled
to the first tubular member in an overlapping relationship. The first and
second tubular members are coupled by the process of deforming a portion of
the second tubular member into contact with a portion of the first tubular
member. In a preferred embodiment, the second tubular member is deformed
by the process of placing the first and second tubular members in an
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overlapping relation ship, radially expanding at least a portion of the first
tubular member, and radially expanding the second tubular member. In a
preferred embodiment, the second tubular member is radially expanded by the
process of supporting the second tubular member and a mandrel within the
wellbore using a support member, injecting a fluidic material into the
wellbore,
pressurizing an interior region of the mandrel, and displacing a portion of
the
mandrel relative to the support member. In a preferred embodiment, the
injecting includes injecting hardenable fluidic sealing material into an
annular
region located between the borehole and the exterior of the second liner, and
injecting non hardenable fluidic material into an interior region of the
mandrel. In a preferred embodiment, the wellbore casing further includes
fluidicly isolating the annular region from the interior region of the mandrel
before injecting the non hardenable fluidic material into the interior region
of
the mandrel. In a preferred embodiment, the injecting of the hardenable
fluidic
sealing material is provided at operating pressures and flow rates ranging
from
about 0 to 5,000 psi and 0 to 1,500 gallons/min. In a preferred embodiment,
the
injecting of the non hardenable 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 non hardenable
fluidic material is provided at reduced operating pressures and flow rates
during an end portion of the radial expansion. In a preferred embodiment, the
fluidic material is injected into one or more pressure chambers. In a
preferred
embodiment, one or more pressure chambers are pressurized. In a preferred
embodiment, the pressure chambers are pressurized to pressures ranging from
about 500 to 9,000 psi. In a preferred embodiment, the wellbore casing further
includes fluidicly isolating an interior region of the mandrel from an
exterior
region of the mandrel. In a preferred embodiment, the interior region of the
mandrel is isolated from the region exterior to the mandrel by inserting one
or
more plugs into the injected fluidic material. In a preferred embodiment, the
wellbore casing further includes curing at least a portion of the fluidic
material,
and removing at least a portion of the cured fluidic material located within
the
second tubular liner. In a preferred embodiment, the wellbore casing further
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includes sealing the overlap between the first and second tubular liners. In a
preferred embodiment, the wellbore casing further includes supporting the
second tubular liner using the overlap with the first tubular liner. In a
preferred embodiment, the wellbore casing further includes testing the
integrity
of the seal in the overlap between the first and second tubular liners. In a
preferred embodiment, the wellbore casing further includes removing at least a
portion of the hardenable fluidic sealing material within the second tubular
liner before curing. In a preferred embodiment, the wellbore casing further
includes lubricating the surface of the mandrel. In a preferred embodiment,
the
wellbore casing further includes absorbing shock. In a preferred embodiment,
the wellbore casing further includes catching the mandrel upon the completion
of the radial expansion. In a preferred embodiment, the wellbore casing
further
includes drilling out the mandrel. In a preferred embodiment, the wellbore
casing further include supporting the mandrel with coiled tubing. In a
preferred embodiment, the mandrel reciprocates. In a preferred embodiment,
the mandrel is displaced in a first direction during the pressurization of the
interior region of the mandrel; and wherein the mandrel is displaced in a
second direction during a de-pressurization of the interior region of the
mandrel. In a preferred embodiment, the second tubular liner is maintained in
a substantially stationary position during the pressurization of the interior
region of the mandrel. In a preferred embodiment, the second tubular liner is
supported by the mandrel during a de-pressurization of the interior region of
the mandrel.
An apparatus for expanding a tubular member has also been described
that includes a support member including a fluid passage, a mandrel movably
coupled to the support member including an expansion cone, at least one
pressure chamber defined by and positioned between the support member and
mandrel fluidicly coupled to the first fluid passage, and one or more
releasable
supports coupled to the support member adapted to support the tubular
member. In a preferred embodiment, the fluid passage includes a throat
passage having a reduced inner diameter. In a preferred embodiment, the
mandrel includes one or more annular pistons. In a preferred embodiment, the
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apparatus includes a plurality of pressure chambers. In a preferred
embodiment, the pressure chambers are at least partially defined by annular
pistons. In a preferred embodiment, the releasable supports are positioned
below the mandrel. In a preferred embodiment, the releasable supports are
positioned above the mandrel. In a preferred embodiment, the releasable
supports comprise hydraulic slips. In a preferred embodiment, the releasable
supports comprise mechanical slips. In a preferred embodiment, the releasable
supports comprise drag blocks. In a preferred embodiment, the mandrel
includes one or more annular pistons, and an expansion cone coupled to the
annular pistons. In a preferred embodiment, one or more of the annular
pistons include an expansion cone. In a preferred embodiment, the pressure
chambers comprise annular pressure chambers.
An apparatus has also been described that includes one or more solid
tubular members, each solid tubular member including one or more external
seals, one or more slotted tubular members coupled to the solid tubular
members, and a shoe coupled to one of the slotted tubular members. In a
preferred embodiment, the apparatus further includes one or more intermediate
solid tubular members coupled to and interleaved among the slotted tubular
members, each intermediate solid tubular member including one or more
external seals. In a preferred embodiment, the apparatus further includes one
or more valve members. In a preferred embodiment, one or more of the
intermediate solid tubular members include one or more valve members.
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 also been described that includes
positioning a mandrel within an interior region of the second tubular member,
pressurizing a portion of the interior region of the mandrel, displacing the
mandrel relative to the second tubular member, and extruding at least a
portion
of the second tubular member off of the mandrel into engagement with the first
tubular member. In a preferred embodiment, the pressurizing of the portion of
the interior region of the mandrel is provided at operating pressures ranging
from about 500 to 9,000 psi. In a preferred embodiment, the pressurizing of
the
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portion of the interior region of the mandrel is provided at reduced operating
pressures during a latter portion of the extruding. In a preferred embodiment,
the method further includes sealing the interface between the first and second
tubular members. In a preferred embodiment, the method further includes
supporting the extruded second tubular member using the interface with the
first tubular member. In a preferred embodiment, the 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 positioning the first and second tubular members in an
overlapping relationship. In a preferred embodiment, the method further
includes fluidicly isolating an interior region of the mandrel an exterior
region
of the mandrel. In a preferred embodiment, the interior region of the mandrel
is fluidicly isolated from the region exterior to the mandrel by injecting one
or
more plugs into the interior of the mandrel. In a preferred embodiment, the
pressurizing of the portion of the interior region of the mandrel 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 method further includes injecting fluidic material beyond the
mandrel. In a preferred embodiment, one or more pressure chambers defined
by the mandrel are pressurized. In a preferred embodiment, the pressure
chambers are pressurized to pressures ranging from about 500 to 9,000 psi. In
a preferred embodiment, the first tubular member comprises an existing section
of a wellbore. In a preferred embodiment, the method further includes sealing
the interface between the first and second tubular members. In a preferred
embodiment, the method further includes supporting the extruded second
tubular member using the first tubular member. In a preferred embodiment,
the method further includes testing the integrity of the seal in the interface
between the first tubular member and the second tubular member. 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 drilling out the mandrel. In a preferred embodiment, the
method further include supporting the mandrel with coiled tubing. In a
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preferred embodiment, the method further includes coupling the mandrel to a
drillable shoe. In a preferred embodiment, the mandrel is displaced in the
longitudinal direction. In a preferred embodiment, the mandrel is displaced in
a first direction during the pressurization and in a second direction during a
de-
pressurization.
An apparatus has also been described that includes one or more primary
solid tubulars, each primary solid tubular including one or more external
annular seals, n slotted tubulars coupled to the primary solid tubulars, n-1
intermediate solid tubulars coupled to and interleaved among the slotted
tubulars, each intermediate solid tubular including one or more external
annular seals, and a shoe coupled to one of the slotted tubulars.
A method of isolating a first subterranean zone from a second
subterranean zone in a wellbore has also been described that includes
positioning one or more primary solid tubulars within the wellbore, the
primary
solid tubulars traversing the first subterranean zone, positioning one or more
slotted tubulars within the wellbore, the slotted tubulars traversing the
second
subterranean zone, fluidicly coupling the slotted tubulars and the solid
tubulars, and preventing the passage of fluids from the first subterranean
zone
to the second subterranean zone within the wellbore external to the solid and
slotted tubulars.
A method of extracting materials from a producing subterranean zone in
a wellbore, at least a portion of the wellbore including a casing, has also
been
described that includes positioning one or more primary solid tubulars within
the wellbore, fluidicly coupling the primary solid tubulars with the casing,
positioning one or more slotted tubulars within the wellbore, the slotted
tubulars traversing the producing subterranean zone, fluidicly coupling the
slotted tubulars with the solid tubulars, fluidicly isolating the producing
subterranean zone from at least one other subterranean zone within the
wellbore, and fluidicly coupling at least one of the slotted tubulars from the
producing subterranean zone. In a preferred embodiment, the method further
includes controllably fluidicly decoupling at least one of the slotted
tubulars
from at least one other of the slotted tubulars.
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CA 02299076 2000-02-22
25791.7
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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