Note: Descriptions are shown in the official language in which they were submitted.
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FORMING A WELLBORE CASING WHILE SIMULTANEOUSLY
DRILLING A WELLBORE
This application is a Divisional of Application Ser. No. 2,300,363 filed March
7, 2000.
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 casirig 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 handli.ng 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 diue to large variations in hole
diameters
drilled in the course of the well, and the large volume of cuttings drilled
and
removed.
Conventionally, at the surface end of the wellbore, a wellhead is formed that
typically includes a surface casing, a number of production and/or drilling
spools,
valving, and a Christmas tree. Typically the wellhead further includes a
concentric
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.
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Conventionally, a wellbore casing cannot be formed during the drilling of
a wellbore. Typically, the wellbore is drilled and then a wellbore casing is
formed
in the newly drilled section of the wellbore. This delays the completion of a
well.
The present invention is directed to overcoming one or more of the
limitations of the existing procedures for forming wellbores and wellheads.
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 reinaining
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
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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.
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 manarel 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
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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.
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 weIlhead is provided.
that includes an outer casing and a plurality of concentric iiiner 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
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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.
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 wellbore, the slotted
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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.
According to another aspect of the present invention, a method of creating
a casing in a borehole while also drilling the borehole is also provided that
includes
installing a tubular liner, a mandrel, and a drilling assembly in the
borehole. A
fluidic material is injected within the tubular liner, mandrel and drilling
assembly.
At least a portion of the tubular liner is radially expanded while the
borehole is
drilled using the drilling assembly. In a preferred embodiment, the injecting
includes injecting the fluidic material within an expandible chamber.
According to another aspect of the present invention, an apparatus is also
provided that includes a support member, the support member including a first
fluid passage; a mandrel coupled to the support member, the mandrel including:
a second fluid passage; a tubular member coupled to the mandrel; and a shoe
coupled to the tubular liner, the shoe including a third fluid passage; and a
drilling
assembly coupled to the shoe; wherein the first, second and third fluid
passages
and the drilling assembly are operably coupled.
According to another aspect of the present invention, a method of forming
an underground pipeline within an underground tunnel including at least a
first
tubular member and a second tubular member, the first tubular member having
an inner diameter greater than an outer diameter of the second tubular member,
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is also provided that includes positioning the first tubular member within the
tunnel; positioning the second tubular member within the tunnel in an
overlapping relationship with the first tubular member; positioning a mandrel
and
a drilling assembly within an interior region of the second tubular member;
injecting a fluidic material within the mandrel, drilling assembly and the
second
tubular member; extruding at least a portion of the second tubular member off
of
the mandrel into engagement with the first tubular member; and drilling the
tunnel.
According to another aspect of the present invention, an apparatus is also
provided that includes a wellbore, the wellbore formed by the process of
drilling
the wellbore; and a tubular liner positioned within the wellbore, the tubular
liner
formed by the process of extruding the tubular liner off of a mandrel while
drilling ~
the wellbore. 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.
According to another aspect of the present invention, a method of forming v
a wellbore casing in a wellbore is also provided that includes drilling out
the cXdan~i~r
wellbore while forming the wellbore casing. S?
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.
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FIG. 5 is a fragmentary cross-sectional view illustrating the drilling out of
a portion of the cured hardenable fluidic sealing material from the new
section of
the well borehole.
FIG. 6 is a cross-sectional view of an embodiment of the overlapping joint
between adjacent tubular members.
FIG. 7 is a fragmentary cross-sectional view of a preferred embodiment of
the apparatus for creating a casing within a well borehole.
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 drillabie 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. 10a 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. lOc is a cross-sectional illustration of the pumping of a fluidic sealing
material into the annular region between the tubular member and the existing
casing.
FIG. lOd is a cross-sectional illustration of the pressurizing of the interior
of the tubular member below the mandrel.
FIG. 10e is a cross-sectional illustration of the extrusion of the tubular
member off of the mandrel.
FIG. 10f 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: l la is a fragmentary cross-sectional view illustrating the drilling of a
new section of a well borehole.
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FIG.11b is a fragmentary cross-sectional view illustrating the placement of
an embodiment of an apparatus for hanging a tubular liner within the new
section
of the well borehole.
FIG. 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.11d 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
weilbore 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.
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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.
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 iIlustration of the isolation of subterranean zones using
expandable tubulars.
FIG. 22a is a fragmentary cross-sectional illustration of an embodiment of
an apparatus for forming a wellbore casing while drilling a welbore.
FIG. 22b is'another fragmentary cross-sectional illustration of the apparatus
of FIG. 22a.
FIG. 22c is another fragmentary cross-sectional illustration of the apparatus
of FIG. 22a.
FIG. 22d is another fragmentary cross-sectional illustration of the apparatus
of FIG. 22a.
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
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members in the wellbore to be joined using an overlapping joint that prevents
fluid
and or gas passage. The apparatus and method further permits a new tubular
member to be supported by an existing tubular member by expanding the new
tubular member into engagement with the existing tubular member. The
apparatus and method further minimizes the reduction in the hole size of the
wellbore casing necessitated by the addition of new sections of wellbore
casing.
An apparatus and method for forming a tie-back liner using an expandable
tubular member is also provided. The apparatus and method permits a tie-back
liner to be created by extruding a tubular member off of a mandrel by
pressurizing
and interior portion of the tubular member. In this manner, a tie-back liner
is
produced. The apparatus and method further permits adjacent tubular members
in the wellbore to be joined using an overlapping joint that prevents fluid
and/or
gas passage. The apparatus and method further permits a new tubular member
to be supported by an existing tubular member by expanding the new tubular
member into engagement with the existing tubular member.
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
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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 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
iri 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.
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An apparatus and method fox.forming a wellbore casing while the wellbore
is drilled is also provided. In this manner, a wellbore casing can be formed
simultaneous with the drilling out of a new section of the wellbore. In a
preferred
embodiment, the apparatus and method is used in combination with one or more
of the apparatus and methods disclosed in the present disclosure for forming
wellbore casings using expandable tubulars., Alternatively, the method and
apparatus can be used to create a pipeline or tunnel in a time efficient
manner.
Referring initially to Figs. 1-5, an embodiment of an apparatus and method
for forming a wellbore casing within a subterranean formation will now be
described. As illustrated in Fig. 1, a wellbore 100 is positioned in a
subterranean
formation 105. The wellbore 100 includes an existing cased section 110 having
a
tubular casing 115 and an annular outer layer of cement 120.
In order to extend the wellbore 100 into the subterranean formation 105,
a drill string 125 is used in a well known manner to drill out material from
the
subterranean formation 105 to form a new section 130.
As illustrated in Fig. 2, an apparatus 200 for forming a wellbore casing in
a subterranean formation is then positioned in the new section 130 of the
wellbore
100: The apparatus 200 preferably includes an expandable mandrel or pig 205, a
tubular member 210, a shoe 215, a lower cup seal 220, an upper cup sea1225, a
fluid passage 230, a fluid passage 235, a fluid passage 240, seals 245, and a
support
member 250.
The expandable mandrel 205 is coupled to and supported by the support
member 250. The expandable mandre1205 is preferably adapted to controllably
expand in a radial direction. The expandable 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 inandre1205 comprises a hydraulic expansion tool as
disclosed in U.S. Patent No. 5,348,095, 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
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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 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 eonventional commercially available shoes such as, for
Tm TM
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 overlappingjoint 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.
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In a preferred embodiment, the shoe 215 includes one or more through and
side outlet ports in fluidic communication with the fluid passage 240. In this
manner, the shoe 215 optimally injects hardenable fluidic sealing material
into the
region outside the shoe 215 and tubular member 210. In a preferred embodiment,
the shoe 215 includes the fluid passage 240 having an inlet geometry that can
receive a dart and/or a ball sealing member. In this manner, the fluid passage
240
can be optimally sealed off by introducing a plug, dart and/or ball sealing
elements
into the fluid passage 230.
The lower cup sea1220 is coupled to and supported by the support member
250. The lower cup 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.
TM
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 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.
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The fluid passage 230 is preferably selected, in the casing running mode of
operation, to transport materials such as drilling mud or formation fluids at
flow
rates and pressures ranging from about 0 to 3,000 gallons/minute and 0 to
9,000
psi in order to minimize drag on the tubular member being run and to minimize
surge pressures exerted on the wellbore which could cause a loss of wellbore
fluids
and lead to hole collapse.
The fluid passage 235 permits fluidic materials to be released from the fluid
passage 230. In this manner, during placement of the apparatus 200 within the
new section 130 of the wellbore 100, fluidic materials 255 forced up the fluid
passage 230 can be released into the wellbore 100 above the tubular member 210
thereby minimizing surge pressures on the wellbore section 130. The fluid
passage
235 is coupled to and positioned within the support member 250. The fluid
passage is further fluidicly coupled to the fluid passage 230.
The fluid passage 235 preferably includes a control valve for controllably
opening and closing the fluid passage 235. In a preferred embodiment, the
control
valve is pressure activated in order to controllably minimize surge 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
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the interior region of the tubular member 210 below the expandable mandre1205
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
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,
TM
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
TM
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
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illustrated) to help stabilize the apparatus 200. In a preferred embodiment,
the
support member 250 comprises coiled tubing.
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
Antisieze
(3100) M In a preferred embodiment, the lubricant 275 comprises Climax 1500
Antisieze (3100) available from Climax Lubricants and Equipment Co. in
Houston,
Tm
TX in order to optimally provide optimum lubrication to faciliate the
expansion
process.
In a preferred embodiment, the support member 250 is thoroughly cleaned
prior to assembly to the remaining portions of the apparatus 200. In this
manner,
the introduction of foreign material into the apparatus 200 is 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
interiorxegion 310 of the tubular member 210 below the expandable mandre1205.
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.
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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 operatingpressure are preferably determined
using conventional empirical methods.
The hardenable fluidic sealing materia1305 may comprise any number of
conventional commercially available hardenable fluidic sealing materials such
as,
for example, slag mix, cement or epoxy. In a preferred embodiment, the
hardenable fluidic sealing material 305 comprises a blended cement prepared
specifically for the particular well section being drilled from Halliburton
Energy
Services in Dallas, TX in order to provide optimal support for tubular member
210
while also maintaining optimum flow characteristics so as to minimize
difficulties
during the displacement of cement in the annular region 315. The optimum blend
of the blended cement is preferably determined using conventional empirical
methods.
The annular region 315 preferably is filled with the material 305 in
sufficient quantities to ensure that, upon radial expansion of the tubular
member
210, the annular region 315 of the new section 130 of the wellbore 100 will be
filled
with materia1305.
In a particularly preferred embodiment, as illustrated in Fig. 3a, the wall
thickness and/or the outer diameter of the tubular member 210 is reduced in
the
region adjacent to the mandrel 205 in order optimally permit placement of the
apparatus 200 in positions in the wellbore with tight clearances. Furthermore,
in
this manner, the initiation of the radial expansion of the tubular member 210
during the extrusion process is optimally facilitated.
As illustrated in Fig. 4, once the annular region 315 has been adequately
filled with material 305, a plug 405, or other similar device, is introduced
into the
fluid passage 240 thereby fluidicly isolating the interior region 310 from the
annular region 315. In a preferred embodiment, a non-hardenable fluidic
material
306 is then pumped into the interior region 310 causing the interior region to
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pressurize. In thi.s manne.r...,_the interior ofthe expanded tubular member
210 will
not contain significant amounts of cured materia1305. This reduces and
simplifies
the cost of the entire process. Alternatively, the material 305 may be used
during
this phase of the process.
Once the interior region 310 becomes sufficiently pressurized, the tubular
member 210 is extruded off of the expandable mandre1205. During the extrusion
process, the expandable mandre1205 may be raised out of the expanded portion
of
the tubular member 210. In a preferred embodiment, during the extrusion
process, the mandre1205 is raised at approximately the same rate as the
tubular
member 210 is expanded in order to keep the tubular member 210 stationary
relative to the new wellbore section 130. In an alternative preferred
embodiment,
the extrusion process is commenced with the tubular member 210 positioned
above
{ the bottom of the new wellbore section 130, keeping the mandre1205
stationary,
and allowing the tubular member 210 to extrude off of the mandrel 205 and fall
down the new welibore 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 materia1305 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
TM
a preferred embodiment, the plug 405 comprises a 1VISC 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 materia1306 ispreferably 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 materia1306 is preferably pumped into the interior region
310
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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
mandre1205, the material composition of the tubular member 210 and expansion
mandre1205, the inner diameter of the tubular member 210, the wall thickness
of
the tubular member 210, the type of lubricant, and the yield strength of the
tubular member 210. In general, the thicker the wall thickness, the smaller
the
inner diameter, and the greater the yield strength of the tubular 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 mandre1205 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 mandre1205 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 ty-pical tensile and compressive
loads.
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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 preferr.ed 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 materia1306 is controllably ramped down when the expandable
mandrel 205 reaches the end portion 260 of the tubular member 210. In this
manner, the sudden release of pressure caused by the complete extrusion of the
tubular member 210 off of the expandable 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 mandre1205, 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
mandre1205 is then pulled out of the wellbore section 130 and a drill bit or
miIl is
used in combination with a conventional drilling assembly 505 to drill out any
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hardened material 305 within the tubular member 210. The materia1305 within
the annular region 315 is then allowed to cure.
As illustrated in Fig. 5, preferably any remaining cured material 305 within
the interior of the expanded tubular member 210 is then removed in a
conventional manner using a conventional drill string 505. The resulting new
section of casing 510 includes the expanded tubular member 210 and an outer
annular layer 515 of cured material 305. The bottom portion of the apparatus
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 sea1725, an upper cup
sea1730,
a fluid passage 735, a fluid passage 740, a support member 745, a body of
lubricant
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750, an overshot connection 755, another support member 760, and a.stabilizer
765.
The expandable mandrel 705 is coupled to and supported by the support
member 745. The expandable mandrel 705 is further coupled to the expandable
mandrel container 710.. The expandable mandrel 705 is preferably adapted to
controllably expand in a radial direction. The expandable mandrel 705 may
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, modified in accordance
withl
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
30l
! 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
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Tm
Tubular Goods (OCTG), automotive grade steel or plastics. In a preferred
embodiment, the tubular member 715 is fabricated from OCTG.
In a preferred embodiment, the tubular member 715 has a substantially
annular cross-section. In a particularly preferred embodiment, the tubular
member 715 has a substantially circular annular cross-section.
The tubular member 715 preferably includes an upper section 805, an
intermediate section 810, and a lower section 815. The upper section 805 of
the
tubular member 715 preferably is defined by the region beginning in the
vicinity
of the mandrel container 710 and ending with the top section 820 of the
tubular
member 715. The intermediate section 810 of the tubular member 715 is
preferably defined by the region beginning in the vicinity of the top of the
mandrel
container 710 and ending with the region in the vicinity of the mandrel 705.
The
~ lower section of the tubular member 715 is preferably defined by the region
beginning in the vicinity of the mandrel 705 and ending at the bottom 825 of
the
tubular member 715.
In a.preferred embodiment, the wall thickness of the upper section 805 of
-the tubular member 715 is greater than the wall thicknesses of the
intermediate
and lower sections 810 and 815 of the tubular member 715 in order to optimally
faciliate the initiation of the extrusion process and optimally permit the
apparatus
700 to be positioned in locations in the wellbore having tight clearances.
The outer diameter and wall thickness of the upper section 805 of the
tubular member 715 may range, for example, from about 1.05 to 48 inches and
1/8
to 2 inches, respectively. In a preferred embodiment, the outer diameter and
wall
thickness of the upper section 805 of the tubular member 715 range from about
3.5
to 16 inches and 3/8 to 1.5 inches, respectively.
The outer diameter and wall thickness of the intermediate section 810 of the
tubular member 715 may range, for example, from about 2.5 to 50 inches and
.1/16
to 1.5 inches, respectively. In a preferred embodiment, the outer diameter and
wall thickness of the intermediate section 810 of the tubular member 715 range
from about 3.5 to 19 inches and 1/8 to 1.25 inches, respectively.
The outer diameter and wall thickness of the lower section 815 of the
tubular member 715 may range, for example, from about 2.5 to 50 inches and
1/16
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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 mandre1705 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 inateria1840 for increasing the strength
of the
shoe 720. In a particularly preferred embodiment, the body of solid
materia1840
comprises aluminum.
The shoe 720 may comprise any number of conventional commercially
~
available shoes such as, for example, Super Seal II Down-Jet float shoe, or
guide
shoe with a sealing sleeve for a latch down plug modified in accordance with
the
teachings of the present disclosure. In a preferred embodiment, the shoe 720
comprises an-aluminum down-jet guide shoe with a sealing sleeve for a latch-
down
plug available from Halliburton Energy Services in Dallas, TX, modified in
accordance with the teachings of the present disclosure, in order to optimize
guiding the tubular member 715 in the wellbore, optimize the seal between the
tubular member 715 and an existing wellbore casing, and to optimally faciliate
the
removal of the shoe 720 by drilling it out after completion of the extrusion
process.
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The lower cup sea1725 is coupled to and supported by the support member
745. The lower cup sea1725 prevents foreign materials from entering the
interior
region of the tubular member 715 above the expandable mandre1705. The lower
cup sea1725 may comprise any number of conventional commercially available cup
TM TM
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
TM
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 sea1730 is coupled to and supported by the support ~nember
760. The upper cup sea1730 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
TM
cups or Selective Injection Packer (SIP) cup modified in accordance with the
teachings of the present disclosure. In a preferred embodiment, the upper cup
seal
730 comprises a SIP cup available from Halliburton Energy Services in Dallas,
TX
in order to optimally provide a debris barrier and contain a body of
lubricant.
The fluid passage 735 permits fluidic materials to be transported to and
from the interior region of the tubular member 715 below the expandable
mandrel
705. The fluid passage 735 is fluidicly coupled to the fluid passage 740. The
fluid
passage 735 is preferably coupled to and positioned within the support member
760, the support member 745, the mandrel container 710, and the expandable
mandrel 705. The fluid passage 735 preferably extends from a position adjacent
to the surface to the bottom of the expandable mandrel 705. The fluid passage
735
is preferably positioned along a centerline of the apparatus 700. The fluid
passage
735 is preferably selected to transport materials such as cement, drilling mud
or
epoxies at flow rates and pressures ranging from about 40 to 3,000
gallons/minute
and 500 to 9,000 psi in order to optimally provide sufficient operating
pressures to
extrude-the tubular member 715 off of the expandable mandre1705.
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.
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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
mandre1205 to be pressurized.
The fluid passage 740 is preferably positioned substantially along the
centerline of the apparatus 700. The fluid passage 740 is preferably, selected
to
convey materials such as cement, drilling mud or epoxies at flow rates and
pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in
order
to optimally fill an annular region between the tubular member 715 and a 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
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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,
,M
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 apreferred 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 weIlbore. The support member 745 may comprise any
number of conventional commercially available support members such as, for
example, steel drill pipe, coiled tubing or other high strength tubular
modified in
accordance with the teachings of the present disclosure. In 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
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the tubular member 7.15. In this manner, the extrusion of.the tubular member
715
off of the expandable mandre1705 is facilitated. The lubricant 705 may
comprise
any number of conventional commercially available lubricants such as, for
example, Lubriplate, chlorine based lubricants, oil based lubricants, or
Climax
Tm
1500 Antisieze (3100). In a preferred embodiment, the lubricant 750 comprises
TM
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; M
Innerstring Flat-Face Sealing Adapter or EZ Drill Setting Tool Stingerlu 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.
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
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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
asealing 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 mandre1705 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 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,
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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.
During
operation of the apparatus 900, the tubular member 915 is preferably extruded
off
of the mandre1906 by pressurizing the interior region 966 of the tubular
member
902. The tubular member 915 preferably has a substantially annular cross-
section.
In a preferred embodiment, the wall thickness of the tubular member 915 is
greater than the wall thickness of the tubular member 902.
The tubular member 915 may be fabricated -from any number of
conventional commercially available materials such as, for example, oilfield
tubulars, low alloy steels, titanium or stainless steels. In a preferred
embodiment,
the tubular member 915 is fabricated from oilfield tubulars in order to
optimally
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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 ofbuckling. 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 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
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910 in..orcler 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.
The various elemetnts 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 inay 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.
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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 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.
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The coupling 922 couples the support member 904 to the mandre1906. 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 mandre1946, 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 substantia.lly
annular
cross-section. The retainer 924 may comprise any number of 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
Tm
commercially available rubber cups such as, for example, TP cups or Selective
Tm
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
,M
(3100). In a preferred embodiment, the lubricant comprises Climax 1500
Antiseize
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Tu+
(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 range, for
example,
from about 0.125 to 3 inches. In a preferred embodiment, the wall thickness of
the
expansion cone 928 ranges from about 0.25 to 0.75 inches in order to optimally
provide adequate compressive, strength with minimal material. The maximum
and minimum outside diameters of the expansion cone 928 may range, for
example, from about 1 to 47 inches. In a preferred embodiment, the maximum and
minimum outside diameters of the expansion cone 928 range from about 3.5 to 19
in order to optimally provide expansion of generally available oilfield
tubulars
The expansion cone 928 may be fabricated from any number of conventional
commercially available materials such as, for example, ceramic, tool steel;
titanium
or low alloy steel. In a preferred embodiment, the expansion cone 928 is
fabricated
from tool steel in order to optimally provide high strength and abrasion
resistance.
The surface hardness of the outer surface of the expansion cone 928 may range,
for
example, from about 50 Rockwell C to 70 Rockwell C. In a preferred embodiment,
the surface hardness of the outer surface of the expansion cone 928 ranges
from
about 58 Rockwell C to 62 Rockwell C in order to optimally provide high yield
strength. In a preferred embodiment, the expansion cone 928 is heat treated to
optimally provide a hard outer surface and a resilient interior body in order
to
optimally provide abrasion resistance and fracture toughness.
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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 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 mandre1906.
The body of cement 932 provides an inner bearing structure for the mandre1906.
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.
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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 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
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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
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.
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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,
aluminum or cast iron. In a preferred embodiment, the upper cone retainer 944
is fabricated from aluminum in order to optimally provide drillability of the
upper
cone retainer 944.
In a particularly preferred embodiment, the upper cone retainer 944 has a
cross-sectional shape designed to provide increased rigidity. In a
particularly
preferred embodiment, the upper cone retainer 944 has a cross-sectional shape
that
is substantially I-shaped to provide increased rigidity and minimize the
amount of
material that would have to be drilled out.
The lubricator mandrel 946 is coupled to the retainer 924, the rubber cup
926, the upper cone retainer 944, the lubricator sleeve 948, and the guide
950.
During operation of the apparatus 900, the lubricator mandrel 946 preferably
contains the body of lubricant in the annular region 972 for lubricating the
interface between the mandrel 906 and the tubular member 902. Preferably, the
lubricator mandrel 946 has a substantially annular cross-section.
The lubricator mandrel 946 may be fabricated from any number of
conventional commercially available materials such as, for example, steel,
aluminum or cast iron. In a preferred embodiment, the lubricator mandre1946 is
fabricated from aluminum in order to optimally provide drillability of the
lubricator mandrel 946.
The lubricator sleeve 948 is coupled to the lubricator mandrel 946, the
retainer 924, the rubber cup 926, the upper cone retainer 944, the lubricator
sleeve
948, and the guide 950. During operation of the apparatus 900, the lubricator
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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 948.
In
a preferred embodiment, seals 949a and 949b are provided between the
lubricator
mandrel 946, lubricator sleeve 948, and rubber cup 926 in order to optimally
seal
off the interior region 972 of the tubular member 902.
The guide 950 is coupled to the lubricator mandrel 946, the retainer 924,
and the lubricator sleeve 948. During operation of the apparatus 900, the
guide
950 preferably guides the apparatus on the support member 904. Preferably, the
guide 950 has a substantially annular cross-section.
The guide 950 may be fabricated from- any number of conventional
commercially available materials such as, for example, steel, aluminum or cast
iron. In a preferred embodiment, the guide 950 is fabricated from aluminum
order to optimally provide drillability of the guide 950.
The fluid passage 952 is coupled to the mandrel 906. During operation of
the apparatus, the fluid passage 952 preferably conveys hardenable fluidic
materials. In a preferred embodiment, the fluid passage 952 is positioned
about
the centerline of the apparatus 900. In a particularly preferred embodiment,
the
fluid passage 952 is adapted to convey hardenable fluidic materials at
pressures
and flow rate ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/min in
order
to optimally provide pressures and flow rates to displace and circulate fluids
during
the installation of the apparatus 900.
The various elements of the mandrel 906 may be coupled using any number
of conventional process such as, for example, threaded connections, welded
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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 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
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includes an inlet geometry that pprmits 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 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
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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 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
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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 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
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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.
Once the interior region 966 becomes sufficiently pressurized, the tubular
members 902 and 915 are extruded off of the mandre1906. The mandre1906 may
be fixed or it may be expandible. During the extrusion process, the mandre1906
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 passaqe 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
TM
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 mandre1906.
For typical tubular members 902 and 915, the extrusion of the tubular
members 902 and 915 off of the expandable mandrel will begin when the pressure
of the interior region 966 reaches approximately 500 to 9,000 psi. In a
preferred
embodiment, the extrusion of the tubular members 902 and 915 off of the
inandrel
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 mandre1906 may be raised out of the
expanded portions of the tubular members 902 and 915 at rates ranging, for
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example, from about 0 to 5 ft/sec. In a preferred embodiment, during the
extxu, sion
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 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 tubulax 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 overlappingjoint. 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 mandre1906 can be minimized. In a preferred
embodiment, the operating pressure is reduced in a substantially linear
fashion
from 100% to about 10% during the end of the extrusion process beginning when
the mandrel 906 has completed approximately all but about the last 5 feet of
the
extrusion process.
In an alternative preferred embodiment, the operating pressure and/or flow
rate of the hardenable fluidic sealing material and/or the non hardenable
fluidic
material are controlled during all phases of the operation of the apparatus
900 to
minimize shock.
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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.
.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 mandre1906 is removed from
the wellbore. In a preferred embodiment, either before or after the removal of
the
mandrel 906, the integrity of the fluidic seal of the overlapping joint
between the
upper portion of the tubular member 915 and the lower portion of the existing
casing is tested using conventional methods. If the fluidic seal of the
overlapping
joint between the upper portion of the tubular member 915 and the lower
portion
of the existing casing is satisfactory, then the uncured portion of any of the
hardenable fluidic sealing material within the expanded tubular member 915 is
then removed in a conventional manner. The hardenable fluidic sealing material
within the annular region between the expanded tubular member 915 and the
existing casing and new section of wellbore is then allowed to cure.
Preferably any remaining cured hardenable fluidic sealing material within
the interior of the expanded tubular members 902 and 915 is then removed in a
conventional manner using a conventional drill string. The resulting new
section
of casing preferably includes the expanded tubular members 902 and 915 and an
outer annular layer of cured hardenable fluidic sealing material. The bottom
portion of the apparatus 900 comprising the shoe 908 may then be removed by
drilling out the shoe 908 using conventional drilling methods.
In an alternative embodiment, during the extrusion process, it may be
necessary to remove the entire apparatus 900 from the iinterior 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 mandre1906 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 mandre1946, the lubricator sleeve 948, the guide 950, the housing
954,
the body of cement 956, the sealing sleeve 958, and the extension tube 960,
are
selected to permit at least some of these components to be drilled out using
conventional drilling methods and apparatus. In this manner, in the event of a
malfunction downhole, the apparatus 900 may be easily removed from the
wellbore.
Referring now to Figs. 10a, lOb, 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. 11a-11f.
In a particularly preferred embodiment, an upper portion of the tubular
liner 1012 overlaps with a lower portion of the tubular liner 1008. In a
particularly
preferred embodiment, an outer surface of the upper portion of the tubular
liner
1012 includes one or more sealing members 1016 for providing a fluidic seal
between the tubular liners 1008 and 1012.
Referring to Fig. 10b, 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
controllably expand in a radial direction. The expandable mandrel 1105 may
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comprise any number of conventional commercially available expandable mandrels
modified in.accordance with the teachings of the-present disclosure. In a
preferred
embodiment, the expandable mandrel 1105 comprises a hydraulic expansion tool
substantially as disclosed in U.S. Pat. No. 5,348,095, modified in accordance
with
the teachings of the present disclosure.
The tubular member 1110 is coupled to and supported by the expandable
mandre11105. The tubular member 1105 is expanded in the radial direction and
extruded off of the expandable mandre11105. The tubular member 1110 may be
fabricated from any number of materials such as, for example, Oilfield Country
Tubular Goods,m13 chromium tubing or plastic piping. In: a preferred
embodiment,
"m
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 optimaIly 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
Tm TM
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 1115
comprises an aluminum down-jet guide shoe with a sealing sleeve for a latch-
down
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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 11.15
( includes one or more of the fluid passages 1140 each having an inlet
geometry that
can receive a dart and/or a bail sealing member. In this manner, the fluid
passages
1140 can be sealed offby 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
TM
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 mandre11105. The fluid passage 1130
preferably extends from a position adjacent to the surface to the bottom of
the
expandable mandrel 1105. The fluid passage 1130 is preferably positioned along
a centerline of the apparatus 1100. The fluid passage 1130 is preferably
selected
to transport materials such as cement, drilling mud or epoxies at flow rates
and
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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.
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
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of the lower end portion of the tubular member 1110. The seals 1145 permit the
overlapping joint between the upper end portion of the casing 1012 and the
lower
end portion of the tubular member 1110 to be fluidicly sealed.
The seals 1145 may comprise any number of conventional commercially
available seals such as, for example, lead, rubber, Teflon or epoxy seals
modified
in accordance with the teachings of the present disclosure. In a preferred
embodiment, the seals 1145 comprise seals molded from Stratalock epoxy
available
from Halliburton Energy Services in Dallas, TX in order to optimally provide a
hydraulic seal in the overlappingjoint and opti-mallyprovide load carrying
capacity
to withstand the range of typical tensile and compressive loads.
In a preferred embodiment, the seals 1145 are selected to optimally provide
a sufficient frictional force to support the expanded tubular member 1110 from
the
tubular liner 1008. In a preferred embodiment, the frictional force provided
by the
seals 1145 ranges from about 1,000 to 1,000,0001bf in tension and compression
in
order to optimally support the expanded tubular member.1110.
The support member 1150 is coupled to the expandable mandrel 1105,
tubular member 1110, shoe 1115, and seal 1120. The support member 1150
preferably comprises an annular member having sufficient strength to carry the
apparatus 1100 into the wellbore 1000. In a preferred embodiment, the support
member 1150 further includes one or more conventional centralizers (not
illustrated) to help stabilize the tubular member 1110.
In a preferred embodiment, a quantity of lubricant 1150 is provided in the
annular region above the expandable mandrel 1105 within the interior of 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. zn 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
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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
Packe 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.
- As illustrated in Fig.10c, a hardenable fluidic sealing materia11160 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 mandre11105. The inateria11160 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 inay 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
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gallons/min, respectively. In a preferred embodiment, the material 1160 is
pumped
into the annular region at pressures and flow rates specifically designed for
the
casing sizes being run, the annular spaces being filled, the pumping equipment
available, and the properties of the fluid being pumped. The optimum flow
rates
and pressures are preferably calculated using conventional empirical methods.
The hardenable fluidic sealing material 1160 may comprise any number of
conventional commercially available hardenable fluidic sealing materials such
as,
for example, slag mix, cement or epoxy. In a preferred embodiment, the
hardenable fluidic sealing material 1160 comprises blended cements
specifically
designed for well section being tied-back, available from Halliburton Energy
Services in Dallas, TX in order to optimally provide proper support for the
tubular
member 1110 while maintaining optimum flow characteristics so as to minimize
operational difficulties during the displacement of cement in the annular
region.
The optimum blend of the blended cements are preferably determined using
conventional empirical methods.
The annular region may be filled with the material 1160 in sufficient
quantities to ensure that, upon radial expansion of the tubular member 1110,
the
annular region will be filled with material 1160.
As illustrated in Fig. lOd, once the annular region has been adequately filled
with materia11160, one or more plugs 1165, or other similar devices,
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
mandre11105 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 nori hardenable.
fluidic
material. In this manner, the amount of hardenable fluidic material within the
interior of the tubular member 1110 is minimized.
As illustrated in Fig. 10e, once the interior region becomes sufficiently
pressurized, the tubular member 1110 is extruded off of the expandable mandrel
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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.
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
belovvathe
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
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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
mandre11105.
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 mandre11105. 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 preferred
embodiment, the contact pressure of the joint betweeri 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
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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.
As illustrated in Fig. 10f, 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
liiier
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. lla, a wellbore 1200 is positioned in a subterranean
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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.11b, 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 mandre11305 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, 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
rM
Country Tubular Goods (OCTG), 13 chromium steel tubing/casing or plastic
casing. In a preferred embodiment, the tubular member 1310 is fabricated from
OCTG. The inner and outer diameters of the tubular member 1310 may range, for
example, from approximately 0.75 to 47 inches and 1.05 to 48 inches,
respectively.
In a preferred embodiment, the inner and outer diameters of the tubular member
1310 range from about 3 to 15.5 inches and 3.5 to 16 inches, respectively in
order
to optimally provide minimal telescoping effect in the most commonly
encountered
wellbore sizes.
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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 11/2 inches and 3V2 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.
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
mandre11305
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.
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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,
T'm Tm
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 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 center.line 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.
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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 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
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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.
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
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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 mandre11305.
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 materia11380 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, and
into
the interior region 1370 of the tubular member 1310 below the expandable
mandrel 1305. The material 1380 then passes.from the interior region 1370 into
the fluid passage 1330. The material 1380 then exits the apparatus 1300 via
the
fluid passage 1335 and fills the annular region 1390 between the exterior of
the
tubular member 1310 and the interior wall of the new section 1230 of the
wellbore
1200. Continued pumping of the materia11380 causes the materia11380 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 embodinient, 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 materia11380 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
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specifically for the well section beirig 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. l ld, 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 pumped through
the
fluid passage 1320 by a non hardenable fluidic materia11381. The wiper dart
1395
then preferably engages the wiper plug 1350.
As illustrated in Fig. lle, in a preferred embodiment, engagement of the
wiper dart 1395 with the wiper plug 1350- causes the wiper plug 1350 to
decouple
from the mandre11305. 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 132.0 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
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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.
In a preferred embodiment, after blocking the fluid passage 1330, the non
=. hardenable fluidic materia11381 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 mandre11305 may be raised
out of the expanded portion of the tubular member 1310 at rates ranging, for
example, from about 0 to 5 ft/sec. In a preferred embodiment, during the
extrusion
process, the expandable mandrel 1305 may be raised out of the expanded portion
of the tubular member 1310 at rates ranging from about 0 to 2 ft/sec in order
to
optimally provide an efficient process, optimally permit operator adjustment
of
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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 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 materia11381 is controllably ramped down when the
expandable
mandre11305 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
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the lower portion of the casing 1215 is tested using conventional methods. If
the..
fluidic seal of the overlapping joint between the upper portion 1355 of the
tubular
member 1310 and the lower portion of the casing 1215 is satisfactory, then the
uncured portion of the material 1380 within the expanded tubular member 1310
is then removed in a conventional manner. The material 1380 within the annular
region 1390 is then allowed to cure.
As illustrated in Fig. 11f, preferably any remaining cured material 1380
within the interior of the expanded tubular member 1310 is then removed in a
conventional manner using a conventional drill string. The resulting new
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
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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 Tubular
Goods
available from various foreign and domestic steel mills. In a preferred
embodiment, the thick wall casing 1510 has a yield strength of about 40,000 to
135,000 psi in order to optimally provide maximum burst, collapse, and tensile
strengths. In a preferred embodiment, the thick wall casing 1510 has a failure
strength in excess of about 5,000 to 20,000 psi in order to optimally provide
maximum operating capacity and resistance to degradation of capacity after
being
drilled through for an extended time period.
The:annular body of cement 1515 provides support for the thick wall casing
1510. The annular body of cement 1515 may be provided using any number of
conventional processes for forming an annular body of cement in a wellbore.
The
annular body of cement 1515 may comprise any number of conventional cement
mixtures.
The outer casing 1520 is coupled to the thick wall casing 1510. The outer
casing 1520 may be fabricated from any number of conventional commercially
available tubular members modified in accordance with the teachings of the
present disclosure. In a preferred embodiment, the outer casing 1520 comprises
any one of the expandable tubular members described above with reference to
Figs.
1-11f.
In a preferred embodiment, the outer casing 1520 is coupled to the thick
wall casing 1510 by expanding the outer casing 1520 into contact with at least
a
portion of the interior surface of the thick wall casing 1510 using any one of
the
embodiments of the processes and apparatus described above with reference to
Figs. 1-llf. In an alternative embodiment, substantially all of the overlap of
the
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outer casing 1520 .viththe 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 tensile and
compressive loads that are experienced during drilling and production
operations.
As iIlustrated 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
Tm
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::b.ody 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
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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. 1-11f.
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-
11f.
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
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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.
The inner casing 1535 may be coupled to the outer casing 1520 or the thick
wall casing 1510. In a preferred embodiment, the inner casing 1535 is coupled
to
the thick wall casing 1510. The inner casing 1535 may be fabricated from any
number of conventional commercially available tubular members modified in
accordance with the teachings of the present disclosure. In a preferred
embodiment, the inner casing 1535 comprises any one of the expandable tubular
members described above with reference to Figs. 1-11f.
In a preferred embodiment, the inner casing 1535 is coupled to the outer
casing 1520 by expanding at least a portion of the inner casing 1535 into
contact
with the interior surface of the thick wall casing 1510 using any one of the
processes and apparatus described above with reference to Figs. 1-11f. In an
alternative preferred embodiment, the entire length of the overlap of the
inner
casing 1535 with the thick wall casing 1510 and intermediate casing 1530
contacts
the inner surfaces of the thick wall casing 1510 and intermediate casing 1530.
The
contact pressure of the interface between the inner casing 1535 and the thick
wall
casing 1510 may range, for example from about 500 to 10,000 psi. In a
preferred
embodiment, the contact pressure between the inner casing 1535 and the thick
wall casing 1510 ranges from about 500 to 10,000 psi in order to optimally
activate
the pressure activated sealing members and to ensure that the joint will
withstand
typical extremes of tensile and compressive loads that are commonly
experienced
during drilling and production operations.
As illustrated in Fig. 13, in a particularly preferred embodiment, the upper
end of the inner casing 1535 includes one or more sealing members 1570 that
provide a gaseous and fluidic seal between the expanded end of the inner
casing
1535 and the interior wall of the thick wall casing 1510. - The sealing
members
1570 may comprise any number of conventional commercially available seals such
as, for example, lead, plastic, rubber, Teflon or epoxy, modified in
accordance with
the teachings of the present disclosure. In a preferred embodiment, the
sealing
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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 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
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preferred embodiment, an annular body 1645 of a compressible. material is
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,
Tefloii,m
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
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large compressible zone, minimize the radial forces required 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 of the
support
member 1705 comprises coiled tubing or a drill pipe. In a particularly
preferred
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embodiment, the support member 1705 includes a load shoulder 1820 for r-- .
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 defmed 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 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
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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
compres'sible 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.
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
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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
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
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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 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.
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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.
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.
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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
embodiment,
the fluidic materia11825 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.
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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 materia11840 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 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
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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.
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
mandre11710, 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,
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-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
5. 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 mandre11710 are removed from the wellbore 1600.
In a pr-eferred 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
expandingoverlappingtubular
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.
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 mandre11935, 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.
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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 drilipipe 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
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 conimercially 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
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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 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
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specialty type threaded connection, or a, standard threaded connection. In a
preferred embodiment, the sealing sleeve 1915 is removably coupled to the
inner
sealing mandre11920 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 mandre11920 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 mandre11920 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.
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 mandre11920
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 mandre11920 is removably coupled to
the
lower sealing head 1930 by a standard threaded connections connection.
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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 mandre11935
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 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.
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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 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 mandre11935. 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 mandre11935 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
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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 mandre11935. The sealing members 2015
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 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 mandre11920 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 inembers 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
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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 mandre11940 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 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
mandre11935, and the expansion cone 1945 reciprocate in the axial direction.
The
radial clearance between the outer surface of the outer sealing mandre11935
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 mandre11935 and the inner surface of the casing
1970
ranges from about 0.025 to 0.125 inches in order to optimally provide maximum
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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 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, driIlpipe 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
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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
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.
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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 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.
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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 exaniple, driIlpipe 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
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 tliickness 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
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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
mandre11940 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 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
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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.
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
Mode13L 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
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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 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
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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 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 mandre11920, lower sealing head 1930, load mandre11940, 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
welibore casing.
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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 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
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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
will
preferably permeate and envelop the expanded casing. In this manner, a new
section of welibore 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 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 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 1 975, 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 mandre12120, 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.
30' The drilipipe 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
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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 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
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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
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.
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The sealing sleeve 2115 preferably includes a fluid passage 2170 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.
The inner sealing mandre12120 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 mandre12120 may be coupled to the sealing sleeve 2115
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilf eld 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
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embodiment, the inner sealing mandre12120 is removably coupled to the lower
sealing head 2135 by a standard threaded connection.
The inner sealing mandre12120 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,
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 Mode13L 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 mandre12120 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
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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 mandre12120 ranges from about
0.005 to 0.010 inches in order to optimally provide a pressure seal. The
radial
clearance between the outer 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
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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 coupling between the upper sealing head
2130 and the outer sealing mandre12140 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 mandre12120
and the load mandre12145.. The lower sealing head 2135 is also movably coupled
to the inner surface of the outer sealing mandre12140. 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 mandre12140 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 mandre12140. 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
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seals. In a preferred embodiment, the 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 mandre12120 includes one or more
sealing members 2230 for fluidicly sealing the interface between the lower
sealing
head 2135 and the inner sealing mandre12120. 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 mandre12145 using
any number of conventional commercially available mechanical couplings such
as,
for example, drilipipe 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 mandre12140 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 mandre12140 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 mandre12140 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 mandre12145 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.
The load mandrel 2145 may be coupled to the lower sealing head 2135 using
any number of conventional commercially available mechanical couplings such
as,
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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 mandre12145 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 mandre12145.
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 mandre12140. 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 mandre12140,
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 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
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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.
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
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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
TM
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
expansiori 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 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
Tm
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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 welibore
with the upper end 2260 of the casing 2155 positioned in an overlapping
relationship with the lower end of an existing weilbore 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 welibore, 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.
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.
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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 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 mandre12140 and expansion cone 2150 to move in an
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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 mandre12140, 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
mandre12140,
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.
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
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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
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 welibore 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
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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 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
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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 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
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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, driIlpipe 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.
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
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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 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
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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 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
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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 mandre12330 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 mandre12330 is fabricated from
stainless
steel in order to optimally provide high strength, corrosion resistance, and
low
friction surfaces.
The inner sealing mandre12330 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 mandre12330
is removably coupled to the hydraulic slip body 2320 by a 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 mandre12330
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.
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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 mandre12330 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
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 mandre12330. 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.
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In a preferred embodiment, the upper sealinghead 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 sealingmembers 2445 comprise polypak seals available
from Parker Seals in order to optimally provide sealing for long axial
strokes.
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
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to optimally provide high strength, corrosi~n resistance, and low friction
surfaces.
The outer surface of the lower sealing hea~ 2340 preferably includes one or
more
annular sealing members 2450 for sealing he interface between the lower
sealing
head 2340 and the outer sealing mandrel 350. The sealing members 2450 may
comprise any number of conventional c mmercially available annular sealing
members such as, for example, o-rings, p lypak seals or metal spring energized
seals. In a preferred embodiment, the se 'ng 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 b coupled to the inner sealing mandrel
2330 using any number of convention commercially available mechanical
couplings such as, for example, drillpipq connection, oilfield country tubular
specialty threaded connection, welding, amprphous bonding, or standard
threaded
connection. In a preferred embodiment, the lower sealing head 2340 is
removably
coupled to the inner sealing mandrel 2330 y a standard threaded connection. In
a preferred embodiment, the mechanical c upling between the lower sealing head
2340 and the inner sealing mandre12330 includes one or more sealing members
2455 for fluidicly sealing the interface between the lower sealing head 2340
and the
inner sealing mandre12330. 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 mandre12345 includes one or more sealing members 2460 for fluidicly
sealing
the interface between the lower sealing head 2340 and the load mandre12345.
The
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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
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 mandre12350 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
mandre12350 may be fabricated from any number of conventional commercially
available materials such as, for example, low alloy steel, carbon steel,
stainless steel
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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, 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 defme a pressure
chamber 2475. The pressure chamber 2475 is fluidicly coupled to the passage
2405
via orie 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
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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 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 mandre12350. 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
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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.
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 mandre12350 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
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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 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
mandre12345 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
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sliding steel retaining rings in order to opti.mally 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.
The mechanical slips 2365 may comprise any number of conventional
TM
commercially available mechanical slips such as, for example, RTTS packer
TM
tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or
Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In a
-TM
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
TM
commercially available mechanical slips such as, for example, RTTS packer
TM
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.
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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, carbori 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, 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
u.pper 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.
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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
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
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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
mandre12345, and mechanical slip body 2360 to move upward. 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 2375, the operating pressure of the second fluidic material is
reduced
in order to minimize shock to the apparatus 2300. In an alternative
embodiment,
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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 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
mandre12330
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
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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 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 drilipipe 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
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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 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, drilipipe 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.
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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.
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 enibodiment, 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 mandre12530. 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
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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 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 mandre12530 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
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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 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.
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
mandre12530 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 mandre12530 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 mandre12530 may be coupled to the lower sealing
head 2540 using any number of conventional commercially available mechanical
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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
mandre12530 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
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 mandre12530 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 mandre12530 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
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embodiment, the upper seali.ng 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 mandre12530. The sealing members 2620 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 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 mandre12545. 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.
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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 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
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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.
The lower sealing head 2540 may be coupled to the load mandre12550 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 mandre12550 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 sealingmembers 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 mandre12545 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 Ynandre12545
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
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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 radial clearance
between the inner surface of the outer sealing mandre12545 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 mandre12545 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 mandre12545 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 mandre12545
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
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via one or more passages 2595. During operation of the apparatus 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 mandre12550 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 mandre12550 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. The
reciprocation
of the expansion cone 2555 causes the casing 2560 to expand in the radial
direction.
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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
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
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outside sealing mandre12545 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 sectiori 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
TM
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 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.
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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 70 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
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 weilbore 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.
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During the positioning of the apparatus 2500 in the welibore, 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.
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.
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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
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
mandre12545,
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
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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 meinber 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.
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
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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 welibore 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-
dianieter 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 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
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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 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
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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. In a
preferred
20- 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
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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.
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
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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 mandre12720 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 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 mandre12720 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.
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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 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 meiriber
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
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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 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
mandre12720 and the second inner sealing mandre12740. 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.
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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.
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
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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 mandre12740. 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
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 mandre12735 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
mandre12735 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
mandre12735
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.
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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. The first outer
sealing mandre12735 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 mandre12740 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
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threaded connection, welding, amorphous bonding, or a standard threaded
connection. In a preferred embodiment, the second inner sealing mandre12740 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 mandre12740 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 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 mandre12740 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 mandre12740
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
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surface of the second inner sealing mandrel 2740 may range, for example, from
about 0.0025 to 0:05 in.ches. 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 prefer-red 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 ta 0.125 inches
in
order to optimally provide stabilization for the expansion cone 2765 during
the
expansion process.
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
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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
mandre12735 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 mandre12735. 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
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 mandre12755 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
mandre12740 and the load mandre12760. 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
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mandrel 2735, second upper sealing head 2745, second outer sealing
mandre12755;
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.
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 embodiinent, 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 mandre12740 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
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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.
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
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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 mandre12735, second upper sealing head 2745, second
outer sealing mandre12755, 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
mandre12755 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 mandre12755 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 mandre12755 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
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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 as, for example,
drilipipe 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 mandre12760 is coupled to the second lower sealinghead 2750 and
the mechanical slip body 2755. The load mandre12760 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 mandre12760 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces.
The load mandre12760 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
20. specialty type threaded connection, ratchet-latch type threaded
connection, or a
standard threaded connection. In a preferred embodiment, the load mandre12760
is removably coupled to the second lower sealing head 2750.by a standard
threaded
connection. The load mandre12760 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
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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 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
country
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 fluidicly
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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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TM
tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or
Mode13L 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
2 790
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
õM
commercially available mechanical slips such as, for example, RTTS packer
mechanical drag blocks or Model 3L retrievable bridge plug drag blocks., In a
TM
preferred embodiment, the drag blocks 2785 comprise RTTS packer xnechanical
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 commerci.ally 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 2 790 includes one or more sealing members
positioned
about the exterior of the casing 2790.
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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 2700 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
passage 2905 thereby fluidicly isolating the fluid passage 2810 from the fluid
passage 2815.
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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 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
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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 welibore 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 optimaIly 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
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.
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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 2 790 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 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
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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 drilipipe 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.
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.
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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 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
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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, drilipipe 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 mandre13020 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 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, drillpip2 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
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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 20 slips 3025 are activated upon the pressurization of the fluid 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 defmed 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 mandre13040, the second upper sealing head 3050,
the
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second outer sealing mandre13060, 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 Mode13 etrievable
bridge plug with hydraulic slips. In a preferred embodiment, the slips 3025
comprise RTTS pa&er 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
mandre13020
and the inner surface of the casing 3075. In this manner, 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
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
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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 fa~ricated 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
mandre13020.
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.
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
mandre13040, second upper sealing head 3050, second outer sealing mandre13060,
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 mandre13040 by a standard
threaded
connection. In a preferred embodiment, the mechanical coupling between the
first
upper sealing head 3030 and the first outer sealing mandre13040 includes one
or
more sealing members 3155 for fluidicly sealing the interface between the
first
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upper sealing head 3030 and the first outer sealing mandre13040. 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
mandre13020 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.
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
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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
mandre13020 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 mandre13020. 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.
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
mandre13045 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 mandre13045. 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.
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The first outer sealing mandre13040 is coupled to the first upper sealing
head 3030 and the second upper sealing head 3050. The first outer sealing
mandre13040 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 mandre13040, 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 mandre13040 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 mandre13040 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 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
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first outer sealing mandre13040 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 mandre13040 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
sealing
head 3050 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the first outer sealing mandre13040 and the second
upper sealing head 3050 includes one or more sealing members 3185 for sealing
the interface between the first outer sealing mandre13040 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 mandre13045 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
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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 mandre13045 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 mandre13045 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 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 man drel 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
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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 mandre13045 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 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 conventioinal =
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.
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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 mandre13040 using any number of conventional commercially available
mechanical couplings such as, for example, drilipipe 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
mandre13040 by a standard threaded connection. In a preferred embodiment, 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
mandre13045 and the load mandre13065. 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
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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
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 mandre13045
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
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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 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 mandre13065 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 mandre13040, second upper sealing head
3050, second outer sealing mandre13060, and the expansion cone 3070
reciprocate
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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 mandre13060 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 mandre13060 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The second outer sealing mandre13060 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
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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 pressure chamber
3190. The first and second pressure chambers, 3175 and 3190, are fluidicly
coupled to the passages, 3095 and 3100, via one or more passages, 3115 and
3120.
During operation of the apparatus 3000, the plug 3230 engages with the throat
passage 3225 to fluidicly isolate the fluid passage 3100 from the fluid
passage 3105.
The pressure chambers, 3175 and 3190, 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 expansion
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
plurality of pressure chambers, 3175 and 3190, effectively multiplies the
available
driving 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 having
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 couplings such
as,
for example, epoxy, cement, water, drilling mud, or lubricants. In a preferred
embodiment, the load mandrel 3065 is removably coupled to the lower sealing
head
3055 by a standard threaded connection.
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The load mandrel 3065 preferably includes a fluid passage 3105 that is
adapted to convey fluidic materials from the fluid passage 3100 to the region
outside of the apparatus 3000. In a preferred embodiment, the fluid passage
3105
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 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
mandre13040, second upper sealing head 3050, second outer sealing mandre13060,
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 ta 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
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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 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
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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
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 weilbore 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
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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.
The lower annular sealing member 3260 may be fabricated from any
number of cQnventional commercially available sealing materials such as, for
example, epoxy, rubber, metal or plastic. In a preferred embodiment, the lower
TM
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
20. 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
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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
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.
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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 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 mandre13040, 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
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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
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
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existing casing and the upper end 3235 of the casing 3075 ranges 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 weIlbore 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
minimize
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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 example,
oilfield
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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 welibore 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, 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.
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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 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.
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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
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.
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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.
Referring to Figures 22a, 22b, 22c and 22d, an embodiment of an apparatus
3500 for forming a wellbore casing while drilling a wellbore will now be
described.
In a preferred embodiment, the apparatus 3500 includes a support member 3505,
a mandrel 3510, a mandrel launcher 3515, a shoe 3520, a tubular member 3525,
a mud motor 3530, a drill bit 3535, a first fluid passage 3540, a second fluid
passage 3545, a pressure chamber 3550, a third fluid passage 3555, a cup
sea13560,
a body of lubricant 3565, seals 3570, and a releasable coupling 3600.
The support member 3505 is coupled to the mandrel 3510. The support
member 3505 preferably comprises an annular member having sufficient strength
to carry and support the apparatus 3500 within the welibore 3575. In a
preferred
embodiment, the support member 3505 further includes one or more conventional
centralizers (not illustrated) to help stabilize the apparatus 3500.
The support member 3505 may comprise one or more sections of
conventional commercially available tubular materials such as, for example,
oilfield
country tubular goods, low alloy steel, stainless steel or carbon steel. In a
preferred embodiment, the support member 3505 comprises coiled tubing or
drillpipe in order to optimally permit the placement of the apparatus 3500
within
a non-vertical wellbore.
In a preferred embodiment, the support member 3505 includes a first fluid
passage 3540 for conveying fluidic materials from a surface location to the
fluid
passage 3545. In a preferred embodiment, the first fluid passage 3540 is
adapted
to convey fluidic materials such as water, drilling mud, cement, epoxy or slag
mix
at operating pressures and flow rates ranging from about 0 to 10,000 psi and 0
to
3,000 gallons/minute.
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The mandrel 3510 is coupled to and supported by the support member 3505.
The mandrel 3510 is also coupled to and supports the mandrel launcher 3515 and
tubular member 3525. The mandrel 3510 is preferably adapted to controllably
expand in a radial direction. The mandrel 3510 may comprise any number of
conventional commercially available mandrels modified in accordance with the
teachings of the present disclosure. In a preferred embodiment, the
mandre13510
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.
In a preferred embodiment, the mandrel 3510 includes one or more conical
sections for expanding the tubular member 3525 in the radial direction. In a
preferred embodiment, the outer surfaces of the conical sections of the
mandrel
3510 have a surface hardness ranging from about 58 to 62 Rockwell C in order
to
optimally radially expand the tubular member 3525.
In a preferred embodiment, the mandrel 3510 includes a second fluid
passage 3545 fluidicly coupled to the first fluid passage 3540 and the
pressure
chamber 3550 for conveying fluidic materials from the first fluid passage 3540
to
the pressure chamber 3550. In a preferred embodiment, the second fluid passage
3545 is adapted to convey fluidic materials such as water, drilling mud,
cement,
epoxy or slag mix at operating pressures and flow rates ranging from about 0
to
12,000 psi and 0 to 3,500 gallons/minute in order to optimally provide
operating
pressure for efficient operation.
The mandrel launcher 3515 is coupled to the tubular member 3525, the
mandrel 3510, and the shoe 3520. The mandrel launcher 3515 preferably
comprises a tapered annular member that mates with at a portion of at least
one
of the conical portions of the outer surface of the mandrel 3510. In a
preferred
embodiment, the wall thickness of the mandrel launcher is less than the wall
thickness of the tubular member 3525 in order to facilitate the initiation of
the
radial expansion process and facilitate the placement of the apparatus in
openings
having tight clearances. In a preferred embodiment, the wall thickness of the
mandrel launcher 3515 ranges from about 50 to 100 % of the wall thickness of
the
tubular member 3525 immediately adjacent to the mandrel launcher 3515 in order
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to optimally faciliate the radial expansion process and facilitate the
insertion of the
apparatus 3500 into wellbore casings and other areas with tight clearances.
The mandrel launcher 3515 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 stainless steel. In a
preferred embodiment, the mandrel launcher 3515 is fabricated from oilfield
country tubular goods of higher strength by lower wall thickness than the
tubular
member 3525 in order to optimally provide a smaller container having
approximately the same burst strength as the tubular member 3525.
The shoe 3520 is coupled to the mandrel launcher 3515 and the releasable
coupling 3600. The shoe 3520 preferably comprises a substantially annular
member. In a preferred embodiment, the shoe 3520 or the releasable coupling
3600 include a third fluid passage 3555 fluidicly coupled to the pressure
chamber
3550 and the mud motor 3530.
The shoe 3520 may comprise any number of conventional commercially
available shoes such as, for example, cement filled, aluminum or composite
modified in accordance with the teachings of the present disclosure. In a
preferred
embodiment, the shoe 3520 comprises a high strength shoe having a burst
strength
approximately equal to the burst strength of the tubular member 3525 and
mandrel launcher 3515. The shoe 3520 is preferably coupled to the mud motor
3520 by a releasable coupling 3600 in order to optimally provide for removal
of the
mud motor 3530 and drill nit 3535 upon the completion of a drilling and casing
operation.
In a preferred embodiment, the shoe 3520 includes a releasable latch
mechanism 3600 for retrieving and removing the mud motor 3530 and drill bit
3535 upon the completion of the drilling and casing formation operations. In a
preferred embodiment, the shoe 3520 further includes an anti-rotation device
for
maintaining the shoe 3520 in a substantially stationary rotational position
during
operation of the apparatus 3500. In a preferred embodiment, the releasable
latch
mechanism 3600 is releasably coupled to the shoe 3520.
The tubular member 3525 is supported by and coupled to the mandrel 3510.
The tubular member 3525 is expanded in the radial direction and extruded off
of
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the mandrel 3510. The tubular.member 3525 may be fabricated from any number
of conventional commercially available materials such as, for example,
Oilfield
TU
Country Tubular Goods (OCTG), 13 chromium steel tubing/casing, automotive
grade steel, or plastic tubing/casing. In a preferred embodiment, the tubular
71
member 3525 is fabricated from OCTG in order to maximize strength after
expansion. The inner and outer diameters of the tubular member 3525 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 3525 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 3525 preferably comprises
an annular member with solid walls.
~ In a preferred embodiment, the upper end portion 3580 of the tubular
member 3525 is slotted, perforated, or otherwise modified to catch or slow
down
the. mandrel 3510 when the mandrel 3510 completes the extrusion of tubular
member 3525. For typical tubular member 3525 materials, the length of the
tubular member 3525 is preferably limited to between about 40 to 20,000 feet
in
length. The tubular member 3525 may comprise a single tubular member or,
alternatively, a plurality of tubular members coupled to one another.
The mud motor 3530 is coupled to the shoe 3520 and the drill bit 3535. The
mud motor 3530 is also fluidicly coupled to the fluid passage 3555. In a
preferred
embodiment, the mud motor 3530 is driven by fluidic materials such as, for
example, drilling mud, water, cement, epoxy, lubricants or slag mix conveyed
from
the fluid passage 3555 to the mud motor 3530. In this manner, the mud motor
3530 drives the drill bit 3535. The operating pressures and flow rates for
operating
mud motor 3530 may range,. for example, from about 0 to 12,000 psi and 0 to
10,000 gallons/minute. In a preferred embodiment, the operating pressures and
flow rates for operating mud motor 3530 range from about 0 to 5,000 psi and 40
to 3,000 gallons/minute.
- The mud motor .3530 may comprise any number of conventional
commercially available mud motors, modified in accordance with the teachings
of
the present disclosure. In a preferred embodiment, the size of the mud motor
3520
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and drill bit 3535 are selected to pass through the interior of the shoe 3520
and the
expanded tubular member 3525. In this manner, the mud motor 3520 and drill bit
3535 may be retrieved from the downhole location upon the conclusion of the
drilling and casing operations.
The drill bit 3535 is coupled to the mud motor 3530. The drill bit 3535 is
preferably adapted to be powered by the mud motor 3530. In this manner, the
drill bit 3535 drills out new sections of the wellbore 3575.
The drill bit 3535 may comprise any number of conventional commercially
available drill bits, modified in accordance with the teachings of the present
disclosure. In a preferred embodiment, the size of the mud motor 3520 and
drill
bit 3535 are selected to pass through the interior of the shoe 3520 and the
expanded tubular member 3525. In this manner, the mud motor 3520 and drill bit
= 3535 may be retrieved from the downhole location upon the conclusion of the
drilling and casing operations. In several alternative preferred embodiments,
the
drill bit 3535 comprises an eccentric drill bit, a bi-centered drill bit, or a
small
diameter drill bit with an hydratilically actuated under reamer.
The first fluid passage 3540 permits fluidic materials to be transported to
the second fluid passage 3545, the pressure chamber 3550, the third fluid
passage
3555, and the mud motor 3530. The first fluid passage 3540 is coupled to and
positioned within the support member 3505. The first fluid passage 3540
preferably extends from a position adjacent to the surface to the second fluid
passage 3545 within the mandrel 3510. The first fluid passage 3540 is
preferably
positioned along a centerline of the apparatus 3500.
The second fluid passage 3545 permits fluidic materials to be conveyed from
the first fluid passage 3540 to the pressure chamber 3550, the third fluid
passage
3555, and the mud motor 3530. The second fluid passage 3545 is coupled to and
positioned within the mandrel 3510. The second fluid passage 3545 preferably
extends from a position adjacent to the first fluid passage 3540 to the bottom
of the
mandre13510. The second fluid passage 3545 is preferably positioned
substantially
along the centerline of the apparatus 3500.
The pressure chamber 3550 permits fluidic materials to be conveyed from
the second fluid passage 3545 to the third fluid passage 3555, and the mud
motor
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3530. The pressure chamber is preferably defined by the region below the
mandrel
3510 and within the tubular member 3525, mandrel launcher 3515, shoe 3520, and
releasable coupling 3600. During operation of the apparatus 3500,
pressurization
of the pressure chamber 3550 preferably causes the tubular member 3525 to be
extruded off of the mandrel 3510.
The third fluid passage 3555 permits fluidic materials to be conveyed from
the pressure chamber 3550 to the mud motor 3530. The third fluid passage 3555
maybe coupled to and positioned within the shoe 3520 or releasable coupling
3600.
The third fluid passage 3555 preferably extends from a position adjacent to
the
pressure chamber 3550 to the bottom of the shoe 3520 or releasable coupling
3600.
The third fluid passage 3555 is preferably positioned substantially along the
centerline of the apparatus 3500.
The fluid passages 3540, 3545, and 3555 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 operational efficiency.
The cup seal 3560 is coupled to and supported by the outer surface of the
support member 3505. The cup seal 3560 prevents foreign materials from
entering
the interior region of the tubular member 3525. The cup seal 3560 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 cup seal 3560 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. In a
preferred
embodiment, the apparatus 3500 includes a plurality of such cup seals in order
to
optimally prevent the entry of foreign material into the interior region of
the
tubular member 3525 in the vicinity of the mandre13510.
In a preferred embodiment, a quantity of lubricant 3565 is provided in the
annular region above the mandrel 3510 within the interior of the tubular
member
3525. In this manner, the extrusion of the tubular member 3525 off of the
mandrel 3510 is facilitated. The lubricant 3565 may comprise any number of
conventional commercially available lubricants such as, for example,
Lubriplate,
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~.
chlorine based lubricants, oil based lubricants ,or Climax 1500 Antisieze
(3100).
In a preferred embodiment, the lubricant 3565 comprises Climax 1500 Antisieze
õM
(3100) available from Climax Lubricants and Equipment Co. in Houston, TX in
order to optimally provide optimum lubrication to faciliate the expansion
process.
The seals 3570 are coupled to and supported by the end portion 3580 of the
tubular member 3525. The seals 3570 are further positioned-on an outer surface
of the end portion 3580 of the tubular member 3525. The seals 3570 permit the
overlapping joint between the lower end portion 3585 of a preexisting section
of
casing 3590 and the end portion 3580 of the tubular -member 3525 to be
fluidicly
sealed. The seals 3570 naay 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
TM
embodiment, the seals 3570 are molded from Stratalock epoxy available from
Halliburton Energy Services in Dallas, TX in order to optimally provide a load
bearing interference f t between the end 3580 of the tubular member 3525 and
the
end 3585 of the pre-existing casing 3590.
In a preferred embodiment, the seals 3570 are selected to optimally provide
a sufficient frictional force to support the expanded tubular member 3525 from
the
pre-existing casing 3590. In a preferred embodiment, the frictional force
optimally
provided by the seals 3570 ranges from about 1,000 to 1,000,000 lbf in order
to
optimally support the expanded tubular member 3525.
t The releasable coupling 3600 is preferably releasably coupled to the bottom
of the shoe 3520. In a preferred embodiment, the releasable coupling 3600
includes fluidic seals for sealing the interface between the releasable
coupling 3600
and the shoe 3520. In this manner, the pressure chamber 3550 may be
pressurized. The releasable coupling 3600 may comprise any number of
conventional commercially available releasable couplings suitable for drilling
operations modified in accordance with the teachings of the present
disclosure.
As illustrated in Figure 22A, during operation of the apparatus 3500, the
apparatus 3500 is preferably initially positioned within a preexisting section
of a
wellbore 3575 including a preexisting section of wellbore casing 3590. In a
preferred embodiment, the upper end portion 3580 of the tubular member 3525 is
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positioned in an overlapping relationship with the lower end 3585 of the
preexisting section of casing 3590. In a preferred embodiment, the apparatus
3500
is initially positioned in the welibore 3575 with the drill bit 353 in contact
with the
bottom of the wellbore 3575. During the initial placement of the apparatus
3500
in the wellbore 3575, the tubular member 3525 is preferably supported by the
mandrel 3510.
As illustrated in Figure 22B, a fluidic material 3595 is then pumped into the
first fluid passage 3540. The fluidic materia13595 is preferably conveyed from
the
first fluid passage 3540 to the second fluid passage 3545, the pressure
chamber
3550, the third fluid passage 3555 and the inlet to the mud motor 3530. The
fluidic
material 3595 may comprise any number of conventional commercially available
fluidic materials such as, for example, drilling mud, water, cement, epoxy or
slag
mix. The fluidic material 3595 may be pumped into the first fluid passage 3540
at
operating pressures and flow rates ranging, for example, from about 0 to 9,000
psi
and 0 to 3,000 gallons/minute.
The fluidic materia13595 will enter the inlet for the mud motor 3530 and
drive the mud motor 3530. The fluidic material 3595 will then exit the mud
motor
3530 and enter the annular region surrounding the apparatus 3500 within the
wellbore 3575. The mud motor 3530 will in turn drive the drill bit 3535. The
operation of the drill bit 3535 will drill out a new section of the wellbore
3575.
In the case where the fluidic material 3595 comprises a hardenable fluidic
material, the fluidic material 3595 preferably is permitted to cure and form
an
outer annular body surrounding the periphery of the expanded tubular member
3525. Alternatively, in the case where the fluidic material 3595 is a non-
hardenable fluidic material, the tubular member 3595 preferably is expanded
into
intimate contact with the interior walls of the wellbore 3575. In this manner,
an
outer annular body is not provided in all applications.
As illustrated in Figure 22C, at some point during operation of the mud
motor 3530 and drill bit 3535, the pressure drop across the mud motor 3530
will
create sufficient back pressure to cause the operating pressure within the
pressure
chamber 3550 to elevate to the pressure necessary to extrude the tubular
member
3525 off of the mandrel 3510. The elevation of the operating pressure within
the
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pressure chamber 3550 will then cause the tubular member 3525 to extrude off
of
the mandrel 3510 as illustrated in Figure 22D. For typical tubular members
3525,
the necessary operating pressure may range, for example, from about 1,000 to
9,000 psi. In this manner, a wellbore casing is formed simultaneous with the
drilling out of a new section of wellbore.
In a particularly preferred embodiment, during the operation of the
apparatus 3500, the apparatus 3500 is lowered into the wellbore 3575 until the
drill bit 3535 is proximate the bottom of the wellbore 3575. Throughout this
process, the tubular member 3525 is preferably supported by the mandrel 3510.
The apparatus 3500 is then lowered until the drill bit 3535 is placed in
contact
with the bottom of the.wellbore 3575. At this point, at least a portion of the
weight
of the tubular member 3525 is supported by the drill bit 3535.
The fluidic niateria13595 is then pumped into the first fluid passage 3540,
second fluid passage 3545, pressure chamber 3550, third fluid passage 3555,
and
the inlet of the mud motor 3530. The mud motor 3530 then drives the drill bit
3535 to drill out a new section of the wellbore 3575. Once the differential
pressure
across the mud motor 3530 exceeds the minimum extrusion pressure for the
tubular member 3525, the tubular member 3525 begins to extrude off of the
mandrel 3510. As the tubular member 3525 is extruded off of the mandre13510,
the weight of the extruded portion of the tubular member 3525 is transferred
to
and supported by the drill bit 3535. In a preferred embodiment, the pumping
pressure of the fluidic material 3595 is maintained substantially constant
throughout this process. At some point during the process of extruding the
tubular member 3525 off of the mandre13510, a sufficient portion of the weight
of
the tubular member 3525 is transferred to the drill bit 3535 to stop the
extrusion
process due to the opposing force. Continued drilling by the drill bit 3535
eventually transfers a sufficient portion of the weight of the extruded
portion of
the tubular member 3525 back to the mandre13510. At this point, the extrusion
of the tubular member 3525 off of the mandre13510 continues. In this manner,
the support member 3505 never has to be moved and no drillpipe connections
have
to be made at the surface since the new section of the wellbore casing within
the
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newly drilled section of wellbore is created by the constant downward feeding
of
the expanded tubular member 3525 off of the mandre13510.
Once the new section of wellbore that is lined with the fully expanded
tubular member 3525 is completed, the support member 3505 and mandrel 3510
are removed from the wellbore 3575. The drilling assembly including the mud
motor 3530 and drill bit 3535 are then preferably removed by lowering a
drillstring
into the new section of wellbore casing and retrieving the drilling assembly
by
using the latch 3600. The expanded tubular member 3525 is then cemented using
conventional squeeze cementing methods to provide a solid annular sealing
member around the periphery of the expanded tubular member 3525.
Alternatively, the apparatus 3500 may be used to repair or form an
underground pipeline or form a support member for a structure. In several
preferred alternative embodiments, the teachings of the apparatus 3500 are
combined with the teachings of the embodiments illustrated in Figures 1-21.
For
example, by operably coupling the mud motor 3530 and drill bit 3535 to the
pressure chambers. used to cause the radial expansion of the tubular members
of
the embodiments illustrated and described with reference to Figures 1-2 1, the
use
of plugs may be eliminated and radial expansion of tubular members can be
combined with the drilling out of new sections of wellbore.
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
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provided at operating pressures and flow rates ranging from about 500 to 9000
psi
and 40 to 3,000 gallons/min. The injecting of the non hardenable fluidic
material
is preferably provided at reduced operating pressures and flow rates during an
end
portion of the extruding. The non hardenable fluidic material is preferably
injected below the mandrel. The method preferably includes pressurizing a
region
of the tubular liner below the mandrel. The region of the tubular liner below
the
mandrel is preferably pressurized to pressures ranging from about 500 to 9,000
psi.
The method 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
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or more sealing members adapted to prevent foreign material from entering an
interior region of the tubular member. The mandrel is preferably expandable.
The tubular member is preferably fabricated from materials selected from the
group consisting of Oilfield Country Tubular Goods, 13 chromium steel
tubing/casing, and plastic casing. The tubular member preferably has inner and
outer diameters ranging from about 3 to 15.5 inches 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 ofjoining 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.
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A liner for use in creating a new section of wellbore casing in a subterranean
formation adjacent to an already existing section of wellbore casing has been
described that includes an annular member. The annular member includes one
or more sealing members at an end portion of the annular member, and one or
more pressure relief passages at an end portion of the annular member.
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 welibore 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
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reduced operating pressures and flow rates during an end portion of the
extruding.
In a preferred embodiment, the fluidic material is injected below the mandrel.
In
a preferred embodiment, a region of the tubular liner below the mandrel is
pressurized. In a preferred embodiment, the region of the tubular liner below
the
mandrel is pressurized to pressures 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 weilbore casing. In a preferred embodiment, the tie-back
liner
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further includes a seal positioned in the overlap between the tubular liner
and the
other existing wellbore casing. In a preferred embodiment, tubular liner is
supported by the overlap with the other existing wellbore casing.
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 with an inner surface of the outer
casing. In a preferred embodiment, the sealing members are selected from the
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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 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
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operating pressures ranging from about 500. to 9,000 psi. In a preferred
embodiment, the pressurizing of the portion of the interior region of the
second
tubular member is provided at operating pressures ranging from about 500 to
9,000 psi. In a preferred embodiment, the pressurizing of the portion of the
interior region of the first and second tubular members is provided at
operating
pressures ranging from about 500 to 9,000 psi. In a preferred embodiment, the
pressurizing of the portion of the interior region of the first tubular member
is
provided at reduced operating pressures during a latter portion of the
expansion.
In a preferred embodiment, the pressurizing of the portion of the interior
region
of the second tubular member is provided at reduced operating pressures during
a latter portion of the expansion. In a preferred embodiment, the pressurizing
of
the portion of the ~ interior region of the first and second tubular members
is
provided at reduced operating pressures during a latter portion of the
expansions.
In a preferred embodiment, the contact between the first tubular member and
the
outer casing is sealed. In a preferred embodiment, the contact between the
second tubular member and the outer casing is sealed. In a preferred
embodiment,
the contact between the first and second tubular members and the outer casing
is
sealed. In a preferred embodiment, the expanded first tubular member is
supported using the contact with the outer casing. In a preferred embodiment,
the expanded second tubular member is supported using the contact with the
outer
casing. In a preferred embodiment, the expanded first and second tubular
members are supported using their contacts with the outer casing. In a
preferred
embodiment, the first and second tubular members are extruded off of a
mandrel.
In a preferred embodiment, the surface of the mandrel is lubricated. In a
preferred embodiment, shock is absorbed. In a preferred embodiment, the
mandrel is expanded in a radial direction. In a preferred embodiment, the
first
and second tubular members are positioned in an overlapping relationship. In a
preferred embodiment, an interior region of the first tubular member is
fluidicly
isolated from an exterior region of the first tubular member. In a preferred
embodiment, an interior region of the second tubular member is fluidicly
isolated
from an exterior region of the second tubular -member. In a preferred
embodiment, the interior region of the first tubular member is fluidicly
isolated
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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 embodiinent, the integrity of the seal in the contact between
the
second tubular member and the outer casing is tested. In a preferred
embodiment, the mandrel is caught upon the completion of the extruding. In a
preferred embodiment, the mandrel is drilled out. In a preferred embodiment,
the mandrel is supported with coiled tubing. In a preferred embodiment, the
mandrel is coupled to a drillable shoe.
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
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supported by contact pressure between an outer surface of the inner casing and
an
inner surface of the outer inner tubular member. In a preferred embodiment,
the
outer tubular member has a yield strength ranging from about 40,000 to 135,000
psi. In a preferred embodiment, the outer tubular member has a burst strength
ranging from about 5,000 to 20,000 psi. In a preferred embodiment, the contact
pressure between the inner tubular members and the outer tubular member
ranges from about 500 to 10,000 psi. In a preferred embodiment, one or more of
the inner tubular members include one or more sealing members that contact
with
an inner surface of the outer tubular member. In a preferred embodiment, the
sealing members are selected from the group consisting of rubber, lead,
plastic, and
epoxy.
= An apparatus has also been described that includes an outer tubular
member, and a plurality of substantially concentric inner tubular members
coupled
to the interior surface of the outer tubular member by the process of
expanding
one or more of the inner tubular members into contact with at least a portion,
of
the interior surface of the outer tubular member: In a preferred embodiment,
the
inner tubular members are expanded by extruding the inner tubular members off
of a mandrel. In a preferred embodiment, the inner tubular members are
expanded by the process of: placing the inner tubular members and a mandrel
within the outer tubular member; and pressurizing an interior portion of the
inner
casing. In a preferred embodiment, during the pressurizing, the interior
portion
of the inner tubular member is fluidicly isolated from an exterior portion of
the
inner tubular member. In a preferred embodiment, the interior portion of the
inner tubular member is pressurized at pressures ranging from about 500 to
9,000
psi. In a preferred embodiment, the apparatus further includes one or more
seals
positioned in the interface between the inner tubular members and the outer
tubular member. In a preferred embodiment, the inner tubular members are
supported by their contact with the outer tubular member.
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
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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, 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
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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 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
include;esting the integrity of the seal in the overlap between the tubular
liner and
the existing wellbore casing. In a preferred embodiment, the method further
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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 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
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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
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
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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 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
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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 ofjoining 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 rarnging from about 500 to 9,000
psi.
In a preferred embodiment, the pressurizing of the 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 an d
second tubular members in an overlapping relationship. In a preferred
embodiment, the method further includes fluidicly isolating an interior region
of
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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 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.
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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.
A method of creating a casing in a borehole while also drilling the borehole
also has been described that includes installing a tubular liner, a mandrel,
and a
drilling assembly in the borehole. A fluidic material is injected within the
tubular
liner, mandrel and drilling assembly. At least a portion of the tubular liner
is
radially expanded while the borehole is drilled using the drilling assembly.
In a
preferred embodiment, the injecting includes injecting the fluidic material
within
an expandible chamber. 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. 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 fluidic material
is
provided at operating pressures and flow rates ranging from about 500 to 9,000
psi
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and 40 to 3,000 gallons/min. In a preferred embodiment, the injecting of the
fluidic material is provided at reduced operating pressures and flow rates
during
an end portion of the radial expansion. In a preferred embodiment, the method
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 tubular
liner. In a
preferred embodiment, the method further includes overlapping the tubular
liner
with an existing welibore 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 includes testing 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 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. 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 wall thickness of the tubular
member is variable. In a preferred embodiment, the mandrel is coupled to a
drillable shoe.
An apparatus has also been described that includes a support member, the
support member including a first fluid passage; a mandrel coupled to the
support
member, the mandrel including: a second fluid passage; a tubular member
coupled
to the mandrel; and a shoe coupled to the tubular liner, the shoe including a
third
fluid passage; and a drilling assembly.coupled to the shoe; wherein the first,
second
and third fluid passages and the drilling assembly are operably coupled. In a
preferred embodiment, the support member further includes: a pressure relief
passage; and a flow control valve coupled to the first fluid passage and the
pressure
relief passage. In a preferred embodiment, the support member further includes
a shock absorber. In a preferred embodiment, the support member includes one
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or more sealing members adapted to prevent foreign material from entering. an
interior region of the tubular member. . In a preferred embodiment, the
support
member includes one or more stabilizers. In a preferred embodiment, the
mandrel
is expandable. In a preferred embodiment, the tubular member is fabricated
from
materials selected from the group consisting of Oilfield Country Tubular
Goods,M
automotive grade steel, plastic and chromium steel. In a preferred embodiment,
the tubular member has inner and outer diameters ranging from about 0.75 to 47
inches and 1.05 to 48 inches, respectively. In a preferred embodiment, the
tubular
member has a plastic yield point ranging from about 40,000 to 135,000 psi. In
a
preferred embodiment, the tubular member includes one or more sealing members
at an end portion. In a preferred embodiment, the tubular member includes one
or more pressure relief holes at an end portion. In a preferred= embodiment,
the
tubular member includes a catching member at an end portion for slowing down
movement of the mandrel. In a preferred embodiment, the support member
comprises coiled tubing. In a preferred embodiment, at least a portion of the
mandrel and shoe are drillable. In a preferred embodiment, the wall thickness
of
the tubular member in an area adjacent to the mandrel is less.than the wall
thickness of the tubular member in an area that is.not adjacent to the
mandrel.
In a preferred embodiment, the apparatus further includes an expandible
chamber.
In a preferred embodiment, the expandible chamber is approximately
cylindrical.
In a preferred embodiment, the expandible chamber is approximately annular.
A method of forming an underground pipeline within an underground
tunnel including at least a first tubular member and a second 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
the
first tubular member within the tunnel; positioning the second tubular member
within the tunnel in an overlapping relationship with the first tubular
member;
positioning a mandrel and a drilling assembly within an interior region of the
second tubular member; injecting a fluidic material within the mandrel,
drilling
assembly and the second tubular member; extruding at least a portion of the
second tubular member off of the mandrel into engagement with the first
tubular
member; and drilling the tunnel. In a preferred embodiment, the injecting of
the
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fluidic material is provided at operating pressures ranging from about 500 to
9,000
psi. In a preferred embodiment, the injecting of the fluidic material 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 expanding the mandrel in a radial
direction. In a preferred embodiment, the method further includes e a 1 i n g
t h e
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 includes supporting
the mandrel with coiled tubing. In a preferred embodiment, the method further
includes coupling the mandrel to a drillable shoe. In a preferred embodiment,
the
fluidic material is injected into an expandible chamber. In a preferred
embodiment, the expandible chamber is substantially cylindrical. In a
preferred
embodiment, the expandible chamber is substantially annular. An apparatus
has also been described that includes a wellbore, the wellbore formed by the
process of drilling the wellbore; and a tubular liner positioned within the
wellbore,
the tubular liner formed by the process of extruding the tubular liner off of
a
mandrel while drilling the wellbore. 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, the interior portion of the tubular liner is pressurized at
pressures
ranging from about 500 to 9,000 psi. In a preferred embodiment, the tubular
liner
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is formed by the process of: placing the tubular liner and mandrel within the
wellbore; and pressurizing an interior portion of the mandrel. In a preferred
embodiment, the interior portion of the mandrel is pressurized at pressures
ranging from about 500 to 9,000 psi. In a preferred embodiment, the apparatus
further includes an annular body of a cured fluidic material coupled to the
tubular
liner. 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 external of the tubular liner. In a preferred
embodiment, the tubular liner overlaps with an existing wellbore casing. In a
preferred embodiment, the apparatus further includes a seal positioned in the
overlap between the tubular liner and the existing wellbore casing. In a
preferred
embodiment, the tubular liner is supported by the overlap with the existing
wellbore casing. In a preferred embodiment, the process of extruding the
tubular
liner includes the pressurizing of an expandible chamber. In a preferred
embodiment, the expandible chamber is substantially cylindrical. In a
preferred
embodiment, the expandible chamber is substantially annular.
A method of forming a wellbore casing in. a wellbore has also been described
that includes drilling out the wellbore while forming the wellbore casing. In
a
preferred embodiment, the forming includes: expanding a tubular member in the
radial direction. In a preferred embodiment, the expanding includes:
displacing
a mandrel relative to the tubular member. In a preferred embodiment, the
displacing includes: expanding an expandible chamber. In a preferred
embodiment, the expandible chamber comprises a cylindrical chamber. In a
preferred embodiment, the expandible chamber comprises an annular chamber.
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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