Note: Descriptions are shown in the official language in which they were submitted.
CA 02613421 2007-11-20
DEMANDES OU BREVETS VOLUMINEUX
LA PRESENTE PARTIE DE CETTE DENIANDE OU CE BREVETS
COMPREND PLUS D'UN TOME.
CECI EST LE TOME DE _2
NOTE: Pour les tomes additionels, veillez contacter le Bureau Canadien des
Brevets.
JUMBO APPLICATIONS / PATENTS
THIS SECTION OF THE APPLICATION / PATENT CONTAINS MORE
THAN ONE VOLUME.
THIS IS VOLUME OF _2
NOTE: For additional volumes please contact the Canadian Patent Office.
CA 02613421 2007-11-20
EXPANDABLE TUBULAR MEMBER AND FABRICATION METHOD
THEREFOR
This is a division of co-pending Canadian Patent Application No. 2,383,231
filed on July 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 casing of the upper interval.
Thus, the
casings are in a nested arrangement with casing diameters decreasing in
downward
direction. Cement annuli are provided between the outer surfaces of the
casings and
the borehole wall to seal the casings from the borehole wall. As a consequence
of this
nested arrangement a relatively large borehole diameter is required at the
upper part
of the wellbore. Such a large borehole diameter involves increased costs due
to heavy
casing handling equipment, large drill bits and increased volumes of drilling
fluid and
drill cuttings. Moreover, increased drilling rig time is involved due to
required
cement pumping, cement hardening, required equipment changes due to large
variations in hole diameters drilled in the course of the well, and the large
volume of
cuttings drilled and removed.
Conventionally at the surface end of the wellbore, a wellhead is formed that
typically includes a surface casing, a number of production and/or drilling
spools,
valving, and a Christmas tree. Typically, the wellhead further includes a
concentric
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.
1
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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
In accordance with one aspect of the present invention there is provided an
expandable tubular member, including: a first tubular section having a first
outer
diameter comprising a first threaded connection; an intermediate tubular
section
coupled to the first tubular section having an intermediate outer diameter;
and a
second tubular section having a second outer diameter coupled to the
intermediate
tubular section having a second outer diameter comprising a second threaded
connection; wherein the first and second outer diameters are greater than the
intermediate outer diameter.
In accordance with another aspect of the present invention there is provided a
method of fabricating an expandable tubular member, comprising: providing a
tubular member having a first end, a second end, and an intermediate portion;
radially expanding the first end and the second end of the tubular member;
forming a
first threaded connection on the first end of the tubular member; and forming
a
second threaded connection on the second end of the tubular member.
In accordance with yet another aspect of the present invention there is
provided an apparatus, comprising: a tubular member formed by the process of
radially expanding an unexpanded tubular member into contact with an
approximately
cylindrical passage using an expansion cone, the unexpanded tubular member
including: a first tubular section having a first outer diameter comprising a
first
threaded connection; an intermediate tubular section coupled to the first
tubular
section having an intermediate outer diameter; and a second tubular section
having a
second outer diameter coupled to the intermediate tubular section having a
second
outer diameter comprising a second threaded connection; wherein the first and
second outer diameters are greater than the intermediate outer diameter.
2
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Brief Description of the Drawings
FIG. 1 is a fragmentary cross-sectional view iIlustratingthe drilli.ng of a
new
section of a well borehole.
FIG. 2 is a fragmentary cross-sectional view illustrating the placement of an
v 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. 3ais another fragmentary cross-sectional view illustrating the injection
of a first quantity of a hardenable fluidic sealing material into the new
section of
the well borehole.
FIG. 4 is a fragmentary cross-sectional view illustrating the injection of a
second quantity of a fluidic material into the new section of the well
borehole.
FIG. 5 is a fragmentary cross-sectional view illustrating the drilling out of
a portion of the cured hardenable fluidic sealing material from the new
section of
the well borehole.
FIG. 6 is a cross-sectional view of an embodiment of the overlapping joint
between adjacent tubular members.
FIG. 7 is a fragmentary cross-sectional view of a preferred embodiment of
the apparatus for creating a casing within a well borehole.
FIG. 8 is a fragmentary cross-sectional illustration of the placement of an
expanded tubular member within another tubular member.
FIG. 9 is a cross-sectional illustration of a preferred embodiment of an
apparatus for forming a casing including a drillable mandrel and shoe.
FIG. 9a is another cross-sectional illustration of the apparatus of FIG. 9.
FIG. 9b is another cross-sectional illustration of the apparatus of FIG. 9.
FIG. 9c is another cross-sectional illustration of the apparatus of FIG. 9.
FIG. 10a is a cross-sectional illustration of a wellbore including a pair of
adjacent overlapping casings.
FIG. lOb is a cross-sectional illustration of an apparatus and method for
creating a tie-back liner using an expandable tubular member.
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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. lOf is a cross-sectional illustration of the tie-back liner before
drilling
out the shoe and packer.
FIG. lOg is a cross-sectional illustration of the completed tie-back liner
created using an expandable tubular member.
FIG. lla is a fragmentary cross-sectional view illustrating the drilling of a
new section of a well borehole.
FIG. 11b is a fragmentary cross-sectional view illustrating the placement of
an embodiment of an apparatus for hanging a tubular liner within the new
section
of the well borehole.
FIG. 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. l ld is a fragmentary cross-sectional view illustrating the introduction
of a wiper dart into the new section of the well borehole.
FIG. 11e 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. llf 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
wellh.ead system utilizing expandable tubular members.
FIG. 13 is a partial cross-sectional iIlustration 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.
4
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FIG. 14b is another iIlustration of the formation of the mono-diameter
wellbore casing.
FIG. 14c is another illustration of the formation of the mono-diameter
wellbore casing.
FIG. 14d is another illustration of the formation of the mono-diameter
welbore casing.
FIG. 14e is another illustration of the formation of the mono-diameter
welbore casing.
FIG. 14f is another illustration of the formation of the mono-diameter
welbore casing.
FIG. 15 is an illustration of an embodiment of an apparatus for expanding
a tubular member.
FIG. 15a is another illustration of the apparatus of FIG. 15.
FIG. 15b is another illustration of the apparatus of FIG. 15.
FIG. 16 is an illustration of an embodiment of an apparatus for forming a
mono-diameter wellbore casing.
FIG. 17 is an illustration of an embodiment of an apparatus for expanding
a tubular member.
FIG. 17a is another illustration of the apparatus of FIG. 16.
FIG. 17b is another illustration of the apparatus of FIG. 16.
FIG. 18 is an illustration of an embodiment of an apparatus for forming a
mono-diameter wellbore casing.
FIG. 19 is an illustration of another embodiment of an apparatus for
expanding a tubular member.
FIG. 19a is another illustration of the apparatus of FIG. 17.
FIG. 19b is another illustration of the apparatus of FIG. 17.
FIG. 20 is an illustration of an embodiment of an apparatus for forming a
mono-diameter wellbore casing.
FIG. 21 is an illustration of the isolation of subterranean zones using
expandable tubulars.
FIG. 22a is a fragmentary cross-sectional illustration of an embodiment of
an apparatus for forming a wellbore casing while drilling a welbore.
5
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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. 22dis another fragmentary cross-sectional iIlustration of the apparatus
of FIG. 22a.
FIG. 23a is a fragmentary cross-section illustration of an embodiment of an
apparatus and method for expanding tubular members.
FIG. 23b is another fragmentary cross-sectional illustration of the apparatus
of FIG. 23a.
FIG. 23c is anotherfragmentary cross-sectional illustration of the apparatus
of FIG. 23a.
FIG. 24a is a fragmentary cross-section illustration of an embodiment of an
apparatus and method for expanding tubular members.
FIG. 24b is another fragmentary cross-sectional illustration of the apparatus
of FIG. 24a.
FIG. 24c is another fragmentary cross-sectional illustration of the apparatus
of FIG. 24a.
FIG. 24d is another fragmentary cross-sectional iIlustration of the apparatus
of FIG. 24a.
FIG. 24e is another fragmentary cross-sectional illustration of the apparatus
of FIG. 24a.
FIG. 25 is a partial cross-sectional illustration of an expansion mandrel
expanding a tubular member.
FIG. 26 is a graphical illustration of the relationship between propagation
pressure and the angle of attack of the expansion mandrel.
FIG. 27 is a cross-sectional illustration of an embodiment of an expandable
connector.
FIG. 28 is a cross-sectional illustration of another embodiment of an
expandable connector.
FIG. 29 is a cross-sectional illustration of another embodiment of an
expandable connector.
6
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FIG. 30 is a cross-sectional illustration of another embodiment of an
expandable connector.
FIG. 31 is a fragmentary cross-sectional illustration of the lubrication of
the
interface between an expansion mandrel and a tubular member during the radial
expansion process.
FIG. 32 is an iIlustration of an embodiment of an expansion mandrel
including a system for lubricating the interface between the expansion mandrel
and a tubular member during the radial expansion of the tubular member.
FIG. 33 is an illustration of an embodiment of an expausion mandrel
including a system for lubricating the interface between the expansion mandrel
and a tubular member during the radial expansion of the tubular member.
FIG. 34 is an illustration of an embodiment of an expansion mandrel
including a system for lubricating the interface between the expansion mandrel
and a tubular member during the radial expansion of the tubular member.
FIG. 35 is an illustration of an embodiment of an expansion mandrel
including a system for lubricating the interface between the expansion mandrel
and a tubular member during the radial expansion of the tubular member.
FIG. 36 is an illustration of an embodiment of an expansion mandrel
including a system for lubricating the interface between the expansion
mandrel.
and a tubular member during the radial expansion of the tubular member.
FIG. 37 is an illustration of an embodiment of an expansion mandrel
including a system for lubricating the interface between the expansion mandrel
and a tubular member during the radial expansion of the tubular memher_
FIG. 38 is an illustration of an embodiment of an expansion mandrel
including a system for lubricating the interface between the expansion mandrel
and a tubular member during the radial expansion of the tubular member.
FIG. 39 is an illustration of a preferred embodiment of an expansion
mandrel including a system for lubricating the interface between the expansion
mandrel and a tubular member during the radial expansion of the, tubular
member.
FIG. 40 is a cross-sectional illustration of the first axial groove of the
expansion mandrel of FIG. 39.
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FIG. 41 is a cross-sectional illustration of the circumferential groove of the
expansion mandrel of FIG. 39.
FIG. 42 is a cross-sectional illustration of one of the second axial grooves
of
the expansion mandrel of FIG. 39.
FIG. 43 is a cross sectional illustration of an embodiment of an expansion
mandrel including internal flow passages having inserts for adjusting the flow
of
lubricant fluids.
FIG. 44 is a cross sectional illustration of the expansion mandrel of FIG. 43
further including an insert having a filter for filtering out foreign
materials from
the lubricant fluids.
FIG. 45 is a cross sectional illustration of a preferred embodiment of an
expandible tubular for use in forming and/or repairing a welibore casing,
pipeline,
or foundation support.
FIG. 46 is a cross sectional illustration of the flared end of a tubular
member
selected for testing.
FIG. 47 is a cross sectional illustration of the flared end of a tubular
member
selected for testing that has structurally failed.
FIG. 48 is a cross sectional illustration of an embodiment of an expandable
tubular member.
FIG. 49 is a flow chart illustration of an embodiment of a method for
fabricating the expandable tubular member of FIG. 48.
FIG. 50a is a cross sectional illustration of a tubular member having upset
end portions.
FIG. 50b is a cross sectional illustration of the tubular member of FIG. 50a
after radial expansion of the upset end portions.
FIG. 50c is a cross sectional illustration of the tubular member of FIG. 50b
further including expandable threaded connections provided in the expanded
upset
end portions.
FIG. 50d is a cross sectional illustration of tubular member of FIG. 50c,
further including protective members provided on the outside diameter of the
upset expanded portions of the tubular member.
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FIG. 50e is a cross sectional illustration of the tubular member of FIG. 50d,
further including a ssaling member provided on the outside diameter of the
intermediate unexpanded portion of the tubular member.
FIG. 51 is an illustration of an embodiment of an expansion cone optimally
adapted to radially expand the tubular member of FIG. 48.
FIG. 52 is an illustration of another embodiinent of an expansion cone
optimally adapted to radially expand the tubular member of FIG. 48.
Fig. 53a is a fragmentary cross-sectional illustration of an embodiment of
a wellbore casing formed using any one of the methods and apparatus for
radially
expanding a tubular member illustrated in Figs. 1-52.
Fig. 53b is a fragmentary cross-sectional illustration of an embodiment of
a method and apparatus for further radially expanding the wellbore casing of
Fig.
53a.
Fig. 53c. is a fragmentary cross-sectional illustration of the wellbore casing
of Fig. 53b after further radial expansion.
Detailed Description of the Illustrative Embodiments
An apparatus and method for forming a wellbore casing within a
subterranean formation is provided. The apparatus and method permits a
wellbore casing to be formed in a subterranean formation by placing a tubular
member and a mandrel in a new section of a wellbore, and then extruding the
tubular member off of the mandrel by pressurizing an interior portion of the
tubular member. The apparatus and method further permits adjacent tubular
members in the wellbore to bejoined using an overlapping join.t 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
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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 eliniinates many of the spools conventionally
required, reduces the height of the Christmas tree facilitating servicing,
lowers the
load bearing areas of the wellhead resulting in a more stable system, and
eliminates costly and expensive hanger systems.
An apparatus and method for forming a mono-diameter well casing is also
provided. The apparatus and method permit the creation of a well casing in a
wellbore having a substantially constant internal diameter. In this manner,
the
operation of an oil or gas well is greatly simplified.
An apparatus and method for expanding tubular members is also provided.
The apparatus and method utilize a piston-cylinder configuration in which a
pressurized chamber is used to drive a mandrel to radially expand tubular
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members. In this manner, higher operating pressures can be utilized.
Throughout
the radial expansion process,'the tubular member is never placed in direct
contact
with the operating pressures. In this manner, damage to the tubular member is
prevented while also permitting controlled radial expansion of the tubular
member
in a wellbore.
An apparatus and method for forming a mono-diameter wellbore casing is
also provided. The apparatus and method utilize a piston-cylinder
configuration
in which a pressurized chamber is used to drive a mandrel to radially expand
tubular members. In this manner, higher operating pressures can be utilized.
Throughput the radial expansion process, the tubular member is never placed in
direct contact with the operating pressures. In this manner, damage to the
tubular
member is prevented while also permitting controlled radial expansion of the
tubular member in a wellbore.
An apparatus and method for isolating one or more subterranean zones
from one or more other subterranean zones is also provided. The apparatus and
method permits a producing zone to be isolated from a nonproducing zone using
a combination of solid and slotted tubulars. In the production mode, the
teachings
of the present disclosure may be used in combination with conventional, well
known, production completion equipment and methods using a series of packers,
solid tubing, perforated tubing, and sliding sleeves, which will be inserted
into the
disclosed apparatus to permit the commingling and/or isolation of the
subterranean zones from each other.
An apparatus and method for 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.
An expandable connector is also provided. In a preferred implementation,
the expandable connector is used in conjunction with one or more of the
disclosed
embodiments for expanding tubular members. In this manner, the expansion of
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a plurality of tubular members coupled to one another using the expandable
connector is optimized.
A lubrication and self-cleaning system for an expansion cone is also
provided. In a preferred implementation, the expansion cone includes one or
more
circumferential grooves and one or more axial grooves for providing a supply
of
lubricating fluid to the trailing edge portion of the interface between the
expansion
cone and a tubular member during the radial expansion process. In this manner,
the frictional forces created during the radial expansion process are reduced
which
results in a reduction in the required operating pressures for radially
expanding
the tubular member. Furthermore, the supply of lubricating fluid preferably
removes loose material from tapered end of the expansion cone that is formed
during the radial expansion process.
A method of testing and selecting tubular members for radial expansion
operations is also provided. In a preferred embodiment, the method provides
tubular members that are optimally suited for radial expansion. In this
manner,
radially expanded tubular members having optimal structural properties are
provided.
An expandable tubular member is provided that includes pre-expanded
ends. In this manner, the subsequent radial expansion of the expandable
tubular
member is optimized.
An expansion cone for expanding a tubular member is also provided that
include a first outer surface having a first angle of attack and a second
outer
surface having a second angle of attack less than the first angle of attack.
In this
manner, the expansion of tubular members is optimally provided.
A two-step process for coupling a first tubular member to a second tubular
member is also provided. During the first stage of the process, the first
tubnlar
member is preferably radially expanded into contact with the interior surface
of
the second tubular member. During the second stage of the process, both
tubular
members are radially expanded. The resulting assembly preferably provides a
substantially constant inside diameter.
In several alternative embodiments, the apparatus and methods are used to
form and/or repair wellbore casings, pipelines, and/or structural supports.
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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 iIlustrated 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 seal 225, a
fluid passage 230, a fluid passage 235, a fluid passage 240, seals 245, and a
support
member 250.
The expandable mandrel 205 is coupled to and supported by the support
member 250. The expandable mandrel 205 is preferably adapted to controllably
expand in a radial direction. The expandable mandrel 205 may comprise any
number of conventional commercially available expandable mandrels modified in
accordance with the teachings of the present disclosure. In a preferred
embodiment, the expandable mandrel 205 comprises a hydraulic expansion tool as
disclosed in U.S. Patent No. 5,348,095, modified in accordance with the
teachings of the
present disclosure.
The tubular member 210 is supported by the expandable mandrel 205. The
tubular member 210 is expanded in the radial direction and extruded off of the
expandable mandrel 205. The tubular member 210 may be fabricated from any
number of conventional commercially available materials such as, for example,
Oilfield Country Tubular Goods (OCTG), 13 chromium steel tubing/casing, or
plastic tubing/casing. In a preferred embodiment, the tubular member 210 is
fabricated from OCTG in order to maximize strength after expansion. The inner
and outer diameters of the tubular member 210 may range, for example, from
approximately 0.75 to 47 inches and 1.05 to 48 inches, respectively. In a
preferred
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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 conventional commercially available shoes such as, for
example, Super Seal IITM float shoe, Super Seal II Down-letTM float shoe or a
guide shoe
with a sealing sleeve for a latch down plug modified in accordance with the
teachings of the present disclosure. In a preferred embodiment, the shoe 215
comprises an aluminum down-jet guide shoe with a sealing sleeve for a latch-
down
plug available from Halliburton Energy Services in Dallas, TX, modified in
accordance with the teachings of the present disclosure, in order to optimally
guide
the tubular member 210 in the wellbore, optimally provide an adequate seal
between the interior and exterior diameters of the overlapping joint between
the
tubular members, and to optimally allow the complete drill out of the shoe and
plug after the completion of the cementing and expansion operations.
In a preferred embodiment, the shoe 215 includes one or more through and
side outlet ports in fluidic communication with the fluid passage 240. In this
manner, the shoe 215 optimally injects hardenable fluidic sealing material
into the
region outside the shoe 215 and tubular member 210. In a preferred embodiment,
the shoe 215 includes the fluid passage 240 having an inlet geometrythat can
receive a dart andJor a ball sealing member. Inthis 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.
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The lower cup seal 220 is coupled to and supported by the support member
250. The lower cup sea1220 prevents foreign materials from entering the
interior
region of the tubular member 210 adjacent to the expandable mandrel 205. The
lower cup seal 220 may comprise any number of conventional comznercially
available cup seals such as, for example, TP cups, or Selective Injection
PackerTM
(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.
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
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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
theinterior region of the tubular member 210 below the expandable mandrel 205
to be pressurized. The fluid passage 240 is preferably positioned
substantially
along the centerline of the apparatus 200.
The fluid passage 240 is preferably selected to convey materials such as
cement, drilling mud or epoxies at flow rates and pressures ranging from about
0
to 3,000 gallons/m.i.nute and 0 to 9,000 psi in order to optimally fillll 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
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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
andJor 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,
lead, rubber, TeflonTM, or epoxy seals modified in accordance with the
teachings of
the present disclosure. In a preferred embodiment, the seals 245 are molded
from
StratalockTM epoxy available from Halliburton Energy Services in Dallas, TX in
order
to optimally provide a load bearing interference fit between the end 260 of
the
tubular member 210 and the end 270 of the existing casing 115.
In a preferred embodiment, the seals 245 are selected to optimally provide
a sufficient frictional force to support the expanded tubular member 210 from
the
existing casing 115. In a preferred embodiment, the frictional force optimally
provided by the seals 245 ranges from about 1,000 to 1,000,000 lbf in order to
optimally support the expanded tubular member 210.
The support member 250 is coupled to the expandable mandrel 205, tubular
member 210, shoe 215, and seals 220 and 225. The support member 250
preferably comprises an annular member having sufficient strength to carry the
apparatus 200 into the new section 130 of the wellbore 100_ In a preferred
embodiment, the support member 250 further includes one or more conventional
centralizers (not illustrated) to help stabilize the apparatus 200. In a
preferred
embodiment, 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 mandre1205 is facilitated. The lubricant 275 may comprise
any
number of conventional commercially available lubricants such as, for example,
Lubriplate, chlorine basedlubricants, oil based lubricants or Climax 1500
AntisiezeTM
17
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(3100). In a preferred embodiment, the lubricant 275 comprises Climax 1500
Antisieze (3100) available from Climax Lubricants and Equipment Co. in
Houston,
TX in order to optimally provide optimum lubrication to faciliate the
expansion
process.
In a preferred embodiment, the support member 250 is thoroughly cleaned
prior to assembly to the remaining portions of the apparatus 200. In this
manner,
the introduction of foreign material into the apparatus 200 is minimized. This
minimizes the possibility offoreign material clogging the various flow
passages and
valves of the apparatus 200.
In a preferred embodiment, before or after positioning the apparatus 200
within the new section 130 of the wellbore 100, a couple of wellbore volumes
are
circulated in order to ensure that no foreign materials are located within the
wellbore 100 that might clog up the various flow passages and valves of the
apparatus 200 and to ensure that no foreign material interferes with the
expansion
process.
As illustrated in Fig. 3, the fluid passage 235 is then closed and a
hardenable
fluidic sealing material 305 is then pumped from a surface location into the
fluid
passage 230. The material 305 then passes from the fluid passage 230 into the
interior region 310 of the tubular member 210 below the expandable mandre1205.
The 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 materia1305 to fill up at least a portion of the annular region
315.
The material 305 is preferably pumped into the annular region 315 at
pressures and flow rates ranging, for example, from about 0 to 5000 psi and 0
to
1,500 gallons/min, respectively. The optimum flow rate and operating pressures
vary as a function of the casing and wellbore sizes, wellbore section length,
available pumping equipment, and fluid properties of the fluidic material
being
pumped. The optimum flow rate and operating pressure are preferably determined
using conventional empirical methods.
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The hardenable fluidic sealing material 305 may comprise any number of
conventional commercially available hardenable fluidic sealing materials such
as,
for example, slag mix, cement or epoxy. In a preferred embodiment, the
hardenable fluidic sealing material 305 comprises a blended cement prepared
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 material 305.
In a particularly preferred embodiment, as illustrated in Fig. 3a, the wall
thickness and/or the outer diameter of the tubular member 210 is reduced in
the
region adjacent to the mandrel 205 in order optimally permit placement of the
apparatus 200 in positions in the wellbore with tight clearances. Furthermore,
in
this manner, the initiation of the radial expansion of the tubular member 210
during the extrusion process is optimally facilitated.
As illustrated in Fig. 4, once the annular region 315 has been adequately
filled with material 305, a plug 405, or other similar device, is introduced
into the
fluid passage 240 thereby fluidicly isolating the interior region 310 from the
annular region 315. In a preferred embodiment, a non-hardenable fluidic
material
306 is then pumped into the interior region 310 causing the interior region to
pressurize. In this manner, the interior of the expanded tubular member 210
will
not contain significant amounts of cured material 305. This reduces and
simplifies
the cost of the entire process. Alternatively, the material 305 may be used
during
this phase of the process. Once the interior region 310 becomes sufficiently
pressurized, the tubular member 210 is extruded off of the expandable mandrel
205. During the extrusion process, the expandable mandrel 205 may be raised
out
of the expanded portion of the tubular member 210. In a preferred embodiment,
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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
mandrel
205 stationary, and allowing the tubular member 210 to extrude off of the
mandrel
205 and fall down the new wellbore section 130 under the force of gravity.
The plug 405 is preferably placed into the fluid passage 240 by introducing
the plug 405 into the fluid passage 230 at a surface location in a
conventional
manner. The plug 405 preferably acts to fluidicly isolate the hardenable
fluidic
sealing materia1305 from the non hardenable fluidic material 306.
The plug 405 may comprise any number of conventional commercially
available devices from plugging a fluid passage such as, for example, Multiple
Stage
CementerTM (MSC) latch-down plug, OmegaTM latch-down plug or three-wiper latch-
down plug modified in accordance with the teachings of the present disclosure.
In
a preferred embodiment, the plug 405 comprises a MSC latch-down plug available
from Halliburton Energy Services in Dallas, TX.
After placement of the plug 405 in the fluid passage 240, a non hardenable
fluidic material 306 is preferably pumped into the interior region 310 at
pressures
and flow rates ranging, for example, from approximately 400 to 10,000 psi and
30
to 4,000 gallons/rnin. In this manner, the amount of hardenable fluidic
sealing
material within the interior 310 of the tubular member 210 is minimized. In a
preferred embodiment, after placement of the plug 405 in the fluid passage
240,
the non hardenable material 306 is preferably pumped into the interior region
310
at pressures and flow rates ranging from approximately 500 to 9,000 psi and 40
to
3,000 gallons/min in order to maximize the extrusion speed.
In a preferred embodiment, the apparatus 200 is adapted to m.in.imize
tensile, burst, and friction effects upon the tubular member 210 during the
expansion process. These effects will depend upon the geometry of the
expansion
mandrel 205, the material composition of the tubular member 210 and expansion
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
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tubular member 210. In general, the thicker the wall thickness, the smaller
the
inner diameter, and the greater the yield strength of the tubular member 210,
then
the greater the operating pressures required to extrude the tubular member 210
off of the mandrel 205.
For typical tubular members 210, the extrusion of the tubular member 210
off of the expandable mandrel will begin when the pressure of the interior
region
310 reaches, for example, approximately 500 to 9,000 psi.
During the extrusion process, the expandable mandrel 205 may be raised
out of the expanded portion of the tubular member 210 at rates ranging, for
example, from about 0 to 5 ft/sec. In a preferred embodiment, during the
extrusion
process, the expandable mandrel 205 is raised out of the expanded portion of
the
tubular member 210 at rates ranging from about flto 2 ft/sec in order to
minimize
the time required for the expansion process while also permitting easy control
of
the expansion process.
When the end portion 260 of the tubular member 210 is extruded off of the
expandable mandrel 205, the outer surface 265 of the end portion 260 of the
tubular member 210 will preferably contact the interior surface 410 of the end
portion 270 of the casing 115 to form an fluid tight overlapping joint. The
contact
pressure of the overlapping joint may range, for example, from approximately
50
to 20,000 psi. In a preferred embodiment, the contact pressure of the
overlapping
joint ranges from approximately 400 to 10,000 psi in order to provide optimum
pressure to activate the annular sealing members 245 and optimally provide
resistance to axial motion to accommodate typical tensile and compressive
loads.
The overlapping joint between the section 410 of the existing casing 115 and
the section 265 of the expanded tubular member 210 preferably provides a
gaseous
and fluidic seal. In a particularly preferred embodiment, the sealing members
245
optimally provide a fluidic and gaseous seal in the overlapping joint.
In a preferred embodiment, the operating pressure and flow rate of the non
hardenable fluidic material 306 is controllably ramped down when the
expandable
mandrel 205 reaches the end portion 260 of the tubular member 210. In this
manner, the sudden release of pressure caused by the complete extrusion of the
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tubular member 210 off of the expandable mandre1205 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
mandrel 205 is then pulled out of the wellbore section 130 and a drill bit or
mill is
used in combination with a conventional drilling assembly 505 to driIl out any
hardened materia1305 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
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embodiment, the expandable mandrel 705 comprises a hydraulic expansion tool
substantially as disclosed in U.S. Patent No. 5,348,095, modified in
accordance with the
teachings of the present disclosure.
The expandable mandrel container 710 is coupled to and supported by the
support member 745. The expandable mandrel container 710 is further coupled
to the expandable mandrel 705. The expandable mandrel container 710 may be
constructed from any number of conventional commercially available materials
such as, for example, Oilfield Country Tubular GoodsTM, stainless steel,
titanium or
high strength steels. In a preferred embodiment, the expandable mandrel
container 710 is fabricated from material having a greater strength than the
material from which the tubular member 715 is fabricated. In this manner, the
container 710 can be fabricated from a tubular material having a thinner wall
thickness than the tubular member 210. This permits the container 710 to pass
through tight clearances thereby facilitating its placement within the
wellbore.
In a preferred embodiment, once the expansion process begins, and the
thicker, lower strength material of the tubular member 715 is expanded, the
outside diameter of the tubular member 715 is greater than the outside
diameter
of the container 710.
The tubular member 715 is coupled to and supported by the expandable
mandrel 705. The tubular member 715 is preferably expanded in the radial
direction and extruded off of the expandable mandrel 705 substantially as
described above with reference to Figs. 1-6. The tubular member 715 may be
fabricated from any number of materials such as, for example, Oilfield Country
Tubular Goods (OCTG), automotive grade steel or plastics. In a preferred
embodiment, the tubular member 715 is fabricated from OCTG.
In a preferred embodiment, the tubular member 715 has a substantially
annular cross-section. In a particularly preferred embodiment, the tubular
member 715 has a substantially circular annular cross-section.
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
24
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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 1.5inches, respectively.
The outer diameter and wall thickness of the intermediate section 810 of the
tubular member 715 may range, for example, from about 2.5 to 50 inches and
1/16
to 1.5 inches, respectively.. In a preferred embodiment, the outer diameter
and
wall thickness of the intermediate section 810 of the tubular member 715 range
from about 3.5 to 19 inches and 1/8 to 1.25 inches, respectively.
The outer diameter and wall thickness of the lower section 815 of the
tubular member 715 may range, for example, from about 2.5 to 50 inches and
1/16
to 1.25 inches, respectively. In a preferred embodiment, the outer diameter
and
wall thickness of the lower section 810 of the tubular member 715 range from
about 3.5 to 19 inches and 1/8 to 1.25 inches, respectively. In a 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,
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perforated, or otherwise modified to catch or slow down the mandrel 705 when
it
completes the extrusion of tubular member 715. In a preferred embodiment, the
length of the tubular member 715 is limited to minimize the possibility of
buckling.
For typical tubular member 715 materials, the length of the tubular member 715
is preferably limited to between about 40 to 20,000 feet in length.
The shoe 720 is coupled to the expandable mandrel 705 and the tubular
member 715. The shoe 720 includes the fluid passage 740. In a preferred
embodiment, the shoe 720 further includes an inlet passage 830, and one or
more
jet ports 835. In a particularly preferred embodiment, the cross-sectional
shape
of the inlet passage 830 is adapted to receive a latch-down dart, or other
similar
elements, for blocking the inlet passage 830. The interior of the shoe 720
preferably includes a body of solid material 840 for increasing the strength
of the
shoe 720. In a particularly preferred embodiment, the body of solid material
840
comprises aluminum.
The shoe 720 may comprise any number of conventional commercially
available shoes such as, for example, Super Seal II Down-Jet float shoe, or
guide
shoe with a sealing sleeve for a latch down plug modified in accordance with
the
teachings of the present disclosure. In a preferred embodiment, the shoe 720
comprises an aluminum down j et 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 drilli.ng it out after completion of the extrusion
process.
The lower cup seal 725 is coupled to and supported by the support member
745. The lower cup seal 725 prevents foreign materials from entering the
interior
region of the tubular member 715 above the expandable mandre1705. The lower
cup seal 725 may comprise any number of conventional commercially available
cup
seals such as, for example, TP cups or Selective Injection Packer (SIP) cups
modified in accordance with the teachings of the present disclosure. In a
preferred
embodiment, the lower cup seal 725 comprises a SIP cup, available from
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Halliburton Energy Services in Dallas, TX in order to optimally provide a
debris
barrier and hold a body of lubricant.
The upper cup seal 730 is coupled to and supported by the support member
760. The upper cup 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
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 mandre1705. The fluid passage
735
is preferably positioned along a centerline of the apparatus 700. The fluid
passage
735 is preferably selected to transport materials such as cement, drilling mud
or
epoxies at flow rates and pressures ranging from about 40 to 3,000
gallons/minute
and 500 to 9,000 psi in order to optimally provide sufficient operating
pressures to
extrude the tubular member 715 off of the expandable mandrel 705.
As described above with reference to Figs_ 1-6, during placement of the
apparatus 700 within a new section of a wellbore, fluidic materials forced up
the
fluid passage 735 can be released into the wellbore above the tubular member
715.
In a preferred embodiment, the apparatus 700 further includes a pressure
release
passage that is coupled to and positioned within the support member 260_ The
pressure release passage is further fluidicly coupled to the fluid passage
735. The
pressure release passage preferably includes a control valve for controllably
opening and closing the fluid passage. In a preferred embodiment, the control
valve is pressure activated in order to controllably minimize surge pressures.
The
pressure release passage is preferably positioned substantially orthogonal to
the
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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
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
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number of conventional commercially available seals such as, for example,
lead,
rubber, Teflon, or epoxy seals modified in accordance with the teachings of
the
present disclosure. In a preferred embodiment, the seals 845 comprise seals
molded from StrataLock epoxy available from Halliburton Energy Services in
Dallas, TX in order to optimally' provide a hydraulic seal and a load bearing
interference fit in the overlapping joint between the tubular member 715 and
an
existing casing with optimal load bearing capacity to support the tubular
member
715.
In a preferred embodiment, the seals 845 are selected to provide a sufficient
frictional force to support the expanded tubular member 715 from the existing
casing. In a preferred embodiment, the frictional force provided by the seals
845
ranges from about 1,000 to 1,000,000 lbf in order to optimally support the
expanded tubular member 715.
The support member 745 is preferably coupled to the expandable mandrel
705 and the overshot connection 755. The support member 745 preferably
comprises an annular member having sufficient strength to carry the apparatus
700 into a new section of a wellbore. The support member 745 may comprise any
number of conventional commercially available support members such as, for
example, steel drill pipe, coiled tubing or other high strength tubular
modified in
accordance with the teachings of the present disclosure. In a preferred
embodiment, the support member 745 comprises conventional drill pipe available
from various steel mills in the United States.
In a preferred embodiment, a body of lubricant 750 is provided in the
annular region above the expandable mandrel container 710 within the interior
of
the tubular member 715. In this manner, the extrusion of the tubular member
715
off of the expandable mandrel 705 is facilitated. The lubricant 705 may
comprise
any number of conventional commercially available lubricants such as, for
example, Lubriplate, chlorine based lubricants, oil based lubricants, or
Climax
1500 Antisieze (3100). In a preferred embodiment, the lubricant 750 comprises
Cli.max 1500 Antisieze (3100) available from Halliburton Energy Services in
Houston, TX in order to optimally provide lubrication to faciliate the
extrusion
process.
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The overshot connection 755 is coupled to the support member 745 and the
support member 760. The overshot connection 755 preferably permits the support
member 745 to be removably coupled to the support member 760. The overshot
connection 755 may comprise any number of conventional commercially available
overshot connections such as, for example, Innerstring Sealing Adapter,
Innerstring Flat-Face Sealing AdapterTM or EZ Drill Setting Tool StingerTM.
In a preferred embodiment, the overshot connection 755 comprises an
Innerstring
AdapterTM 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 illust.rated). 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
of conventional commercially available stabilizers such as, for example, EZ
Drill
StarGuidesTM, packer shoes or drag blocks modified in accordance with the
teachings
of the present disclosure. In a preferred embodiment, the stabilizer 765
comprises
a sealing adapter upper guide available from Hallitiurton 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
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is minimized. This minimizes the possibility of foreign material clogging the
various flow passages and valves of the apparatus 700.
In a preferred embodiment, before or after positioning the apparatus 700
within a new section of a wellbore, a couple of wellbore volumes are
circulated
through the various flow passages of the apparatus 700 in order to ensure that
no
foreign materials are located within the wellbore that might clog up the
various
flow passages and valves of the apparatus 700 and to ensure that no foreign
material interferes with the expansion mandrel 705 during the expansion
process.
In a preferred embodiment, the apparatus 700 is operated substantially as
described above with reference to Figs. 1-7 to form a new section of casing
within
a wellbore.
As illustrated in Fig. 8, in an alternative preferred embodiment, the method
and apparatus described herein is used to repair an existing wellbore casing
805
by forming a tubular liner 810 inside of the existing wellbore casing 805. In
a
preferred embodiment, an outer annular lining of cement is not provided in the
repaired section. In the alternative preferred embodiment, any number of
fluidic
materials can be used to expand the tubular liner 810 into 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 usedto transport hydrocarbons or water, with the tubular liner 810
placed
in an overlapping relationship with the adjacent pipeline section. In this
manner,
underground pipelines can be repaired without having to dig out and replace
the
damaged sections.
In another alternative preferred embodiment, the method and apparatus
described herein is used to directly line a wellbore with a tubular liner 810.
In a
preferred embodiment, an outer annular lining of cement is not provided
between
the tubular li.ner 810 and the wellbore. In the alternative preferred
embodiment,
any number of fluidic materials can be used to expand the tubular liner 810
into
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intimate contact with the weilbore 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 expandable tubular
member 902, a support member 904, an expandable mandrel or pig 906, and a shoe
908. In a preferred embodiment, the design and construction of the mandre1906
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 expandable 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 mandrel 906 by pressurizing the interior region 966 of the tubular
member
902. The tubular member 915 preferably has asubstantially annular cross-
section.
In a preferred embodiment, the wall thickness of the tubular member 915 is
greater than the wall thickness of the tubular member 902.
The tubular member 915 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
tubulars, low alloy steels, titanium or stainless steels. In a preferred
embodiment,
the tubular member 915 is fabricated from oilfield tubulars in order to
optimally
provide approximately the same mechanical properties as the tubular member
902.
In a particularly preferred embodiment, the tubular member 915 has a
plasticyield
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.
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In a preferred embodiment, the upper end portion of the tubular member
915 includes one or more sealing members for optimally providing a fluidic
and/or
gaseous seal with an existing section of wellbore casing.
In a preferred embodiment, the combined length of the tubular members
902 and 915 are limited to minimize the possibility of buckling. For typical
tubular
member materials, the combined length of the tubular members 902 and 915 are
limited to between about 40 to 20,000 feet in length.
The lower portion 914 of the tubular member 902 is preferably coupled to
the shoe 908 by a threaded connection 968. The intermediate portion 912 of the
tubular member 902 preferably is placed in intimate sliding contact with the
mandrel 906.
The tubular member 902 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
tubulars, low alloy steels, titanium or stainless steels. In a preferred
embodiment,
the tubular member 902 is fabricated from oilf'ield 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
910 in order to optimally provide a geometry that will fit into tight
clearances
downhole.
The outer diameter of the upper, intermediate, and lower portions, 910, 912
and 914 of the tubular member 902 may range, for example, from about 1.05 to
48
inches. In a preferred embodiment, the outer diameter of the upper,
intermediate,
and lower portions, 910, 912 and 914 of the tubular member 902 range from
about
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3~/a 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 accordan.ce with the
teachings
of the present disclosure. In a preferred embodiment, the tubular member 902
comprises Oiltield 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 pi-eferred embodiment, the tubular member 915
colnprises
Oilfield Country Tubular Goods available from various U.S. steel mills.
The various elements of the tubular member 902 may be coupled using any
number of conventional process such as, for example, threaded connections,
welding or machined from one piece. In a preferred embodiment, the various
elements of the tubular member 902 are coupled using welding. The tubular
member 902 may comprise a plurality of tubular elements that are coupled end
to
end. The various elements of the tubular member 915 may be coupled using any
number of conventional process sucb 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 uaing welding. The tubular
member 915 may comprise a plurality of tubular elements that are coupled end
to
end. The tubular menibers 902 and 915 may be coupled using any number of
conventional process such as, for example, threaded connections, welding or
machined from one piece.
The support member 904 preferably includes an innerstring adapter 916,
a fluid passage 918, an upper guide 920, and a coupling 922. During operation
of
the apparatus 900, the support member 904 preferably supports the apparatus
900
during movement of the apparatus 900 within a wellbore. The support member
904 preferably has a substantially annular cross-section.
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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 Halhburton Energy Services in Dallas, TX
order
to optimally guide the apparatus 900 within the tubular member 915.
The coupling 922 couples the support member 904 to the mandrel 906. The
coupling 922 preferably comprises a conventional threaded connection.
The various elements of the support member 904 may be coupled using any
number of conventional processes such as, for example, welding, threaded
I ._
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connections or machined from one piece. In a preferred embodiment, the various
elements of the support member 904 are coupled using threaded connections.
The mandrel 906 preferably includes a retainer 924, a rubber cup 926, an
expansion cone 928, a lower cone retainer 930, a body of cement 932, a lower
guide
934, an extension sleeve 936, a spacer 938, a housing 940, a sealing sleeve
942, an
upper cone retainer 944, a lubricator mandrel 946, a lubricator sleeve 948, a
guide
950, and a fluid passage 952.
The retainer 924 is coupled to the lubricator mandrel 946, lubricator sleeve
948, and the rubber cup 926. The retainer 924 couples the rubber cup 926 to
the
lubricator sleeve 948. The retainer 924 preferably has a substantially annular
cross-section. The retainer 924 may comprise any number of conventional
commercially available retainers such as, for example, slotted spring pins or
roll
pin.
The rubber cup 926 is coupled to the retainer 924, the lubricator mandrel
946, and the lubricator sleeve 948. The rubber cup 926 prevents the entry of
foreign materials into the interior region 972 of the tubular member 902 below
the
rubber cup 926. The rubber cup 926 may comprise any number of conventional
commercially available rubber cups such as, for example, TP cups or Selective
Injection Packer (SIP) cup. In a preferred embodiment, the rubber cup 926
comprises a SIP cup available from Halliburton Energy Services in Dallas, TX
in
order to optimally block foreign materials.
In a particularly preferred embodiment, a body of lubricant is further
provided in the interior region 972 of the tubular member 902 in order to
lubricate
the interface between the exterior surface of the inandrel 902 and the
interior
surface of the tubular members 902 and 915. The lubricant may comprise any
number of conventional commercially available lubricants such as, for example,
Lubriplate, chlorine based lubricants, oil based lubricants or Climax 1500
Antiseize
(3100). In apreferred embodiment, the lubricant comprises Climax 1500
Antiseize
(3100) available from Climax Lubricants and Equipment Co. in Houston, TX in
order to optimally provide lubrication to faciliate the extrusion process.
The expansion cone 928 is coupled to the lower cone retainer 930, the body
of cement 932, the lower guide 934, the extension sleeve 936, the housing 940,
and
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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 maybe fabricated from any number of conventional
commercially available materials such as, for example, ceramic, tool steel,
titanium
or low alloy steel. In a preferred embodiment, the expansion cone 928 is
fabricated
from tool steel in order to optimally provide high strength and abrasion
resistance.
The surface hardness of the outer surface of the expansion cone 928 may range,
for
example, from about 50 Rockwell C to 70 Rockwell C. In a preferred embodiment,
the surface hardness of the outer surface of the expansion cone 928 ranges
from
about 58 Rockwell C to 62 Rockwell C in order to optimally provide high yield
strength. In a preferred embodiment, the expansion cone 928 is heat treated to
optimally provide a hard outer surface and a resilient interior body in order
to
optimally provide abrasion resistance and fracture toughness.
The lower cone retainer 930 is coupled to the expansion cone 928 and the
housing 940. In a preferred embodiment, axial movement of the expansion cone
928 is prevented by the lower cone retainer 930. Preferably, the lower cone
retainer 930 has a substantially annular cross-section.
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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 mandrel 906.
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.
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.
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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 extensiozi 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 extensionsleeve 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 opti:mally provide drillability. The end of the spacer 938 preferably
mates
with the end of the extension tube 960. In a preferred embodiment, the spacer
938 and the sealing sleeve 942 are formed as an integral one-piece element in
order
to reduce the number of components and increase the strength of the apparatus.
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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.
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.
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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 lubrica.ting the
interface between the mandrel 906 and the tubular member 902. Preferably, the
lubricator mandrel 946 has a substantially annular cross-section.
The lubricator mandrel 946 may be fabricated from any number of
conventional commercially available materials such as, for example, steel,
aluminum or cast iron. In a preferred embodiment, the lubricator mandre1946 is
fabricated from aluminum in order to optimally provide drillability of the
lubricator mandrel 946.
The lubricator sleeve 948 is coupled to the lubricator mandrel 946, the
retainer 924, the rubber cup 926, the upper cone retainer 944, the lubricator
sleeve
948, and the guide 950. During operation of the apparatus 900, the lubricator
sleeve 948 preferably supports the rubber cup 926. Preferably, the lubricator
sleeve 948 has a substantially annular cross-section.
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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 mandre1946, the retainer 924,
and the lubricator sleeve 948. During operation of the apparatus 900, the
guide
950 preferably guides the apparatus on the support member 904. Preferably, the
guide 950 has a substantially annular cross-section.
The guide 950 may be fabricated from any number of conventional
commercially available materials such as, for example, steel, aluminum or cast
iron. In a preferred embodiment, the guide 950 is fabricated from aluminum
order to optimally provide drillability of the guide 950.
The fluid passage 952 is coupled to the mandrel 906. During operation of
the apparatus, the fluid passage 952 preferably conveys hardenable fluidic
materials. In a preferred embodiment, the fluid passage 952 is positioned
about
the centerline of the apparatus 900. In a particularly preferred embodiment,
the
fluid passage 952 is adapted to convey hardenable fluidic materials at
pressures
and flow rate ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/min in
order
to optimally provide pressures and flow rates to displace and circulate fluids
during
the installation of the apparatus 900.
The various elements of the mandrel 906 may be coupled using any number
of conventional process such as, for example, threaded connections, welded
connections or cementing. In a preferred embodiment, the various elements of
the
mandrel 906 are coupled using threaded connections and cementing.
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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 alum9num 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 sealingsleeve
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 driAable
material such as, for example, aluminum or iron may be substituted for the
body
of cement 956.
The sealing sleeve 958 is coupled to the body of cement 956, the extension
tube 960, the fluid passage 962, and one or more outlet jets 964. During
operation
of the apparatus 900, the sealing sleeve 958 preferably is adapted to convey a
hardenable fluidic material from the fluid passage 952 into the fluid passage
962
and then into the outlet jets 964 in order to inject the hardenable fluidic
material
into an annular region external to the tubular member 902. In a preferred
embodiment, during operation of the apparatus 900, the sealing sleeve 958
further
includes an inlet geometry that permits a conventional plug or dart 974 to
become
lodged in the inlet of the sealing sleeve 958. In this manner, the fluid
passage 962
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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 alumi.num 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 embodinient, the extension tube 960 has a substantially
annular cross-section. The extension tube 960 maybe fabricated from any number
of conventional conunercially available materials such as, for example, steel,
aluminum or cast iron. In a preferred embodiment, the extension tube 960 is
fabricated from aluminum in order to optimally provide drillability of the
extension tube 960.
The fluid passage 962 is coupled to the sealing sleeve 958, the extension
tube 960, and one or more outlet jets 964. During operation of the apparatus
900,
the fluid passage 962 is preferably conveys-_hardenable fluidic materials. In
a
preferred embodiment, the fluid passage 962 is positioned about the centerline
of
the apparatus 900. In a particularly preferred embodiment, the fluid passage
962
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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
optunally
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 driIl string is used in a well known manner to drill out material from the
subterranean formation to form a new section.
The apparatus. 900 for forming a wellbore casing in a subterranean
formation is then positioned in the new section of the wellbore. In a
particularly
preferred embodiment, the apparatus 900 includes the tubular member 915. In a
preferred embodiment, a hardenable fluidic sealing hardenable fluidic sealing
material is then pumped from a surface location into the fluid passage 918.
The
hardenable fluidic sealing material then passes from the fluid passage 918
into the
interior region 966 of the tubular member 902 below the mandrel 906. The
hardenable fluidic sealing material then passes from the interior region 966
into
the fluid passage 962. The hardenable fluidic sealing material then exits the
apparatus 900 via the outlet jets 964 and fills an annular region between the
exterior of the tubular member 902 and the interior wall of the new section of
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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 seali.ng material comprises blended cements designed
specifically for the well section being lined available from Halliburton
Energy
Services in Dallas, TX in order to optimally provide support for the new
tubular
member while also maintaining optimal flow characteristics so as to minimize
operational difficulties during the displacement of the cement in the annular
region. The optimum composition of the blended cements is preferably
determined
using conventional empirical methods.
The annular region preferably is filled with the hardenable fluidic sealing
material in sufficient quantities to ensure that, upon radial expansion of the
tubular member 902, the annular region of the new section of the wellbore will
be
filled with hardenable material.
Once the annular region has been adequately filled with hardenable fluidic
sealing material, a plug or dart 974, or other similar device, preferably is
introduced into the fluid passage 962 thereby fluidicly isolating the interior
region
966 of the tubular member 902 from the external annular region. In a preferred
embodiment, a non hardenable fluidic material is then pumped into the interior
region 966 causing the interior region 966 to pressurize. In a particularly
preferred embodiment, the plug or dart 974, or other similar device,
preferably is
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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 mandrel 906. The mandre1906 may
be fixed or it may be expandable. 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 passage such
as,
for example, Multiple Stage Cementer (MSC) latch-down plug, Omega latch-down
plug or three-wiper latch down plug modified in accordance with the teachings
of
the present disclosure. In a preferred embodiment, the plug or dart 974
comprises
a MSC latch-down plug available from Halliburton Energy Services in Dallas,
TX.
After placement of the plug or dart 974 in the fluid passage 962, the non
hardenable fluidic material is preferably pumped into the interior region 966
at
pressures and flow rates ranging from approximately 500 to 9,000 psi and 40 to
3,000 gallons/min in order to optimally extrude the tubular members 902 and
915
off of the mandrel 906.
For typical tubular members 902 and 915, the extrusion of the tubular
members 902 and 915 off of the expandable mandrel will begin when the pressure
of the interior region 966 reaches approximately 500 to 9,000 psi. In a
preferred
embodiment, the extrusion of the tubular members 902 and 915 off of the
mandrel
906 begins when the pressure of the interior region 966 reaches approximately
1,200 to 8,500 psi with a flow rate of about 40 to 1250 gallons/minute.
During the extrusion process, the mandrel 906 may be raised out of the
expanded portions of the tubular members 902 and 915 at rates ranging, for
example, from about 0 to 5 ft/sec. In a preferred embodiment, during the
extrusion
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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 pulli.ng speed fast enough to permit efficient operation and
permit full expansion of the tubular members 902 and 915 prior to curing of
the
hardenable fluidic sealing material; but not so fast that timely adjustment of
operating parameters during operation is prevented.
When the upper end portion of the tubular member 915 is extruded off of
the mandrel 906, the outer surface of the upper end portion of the tubular
member
915 will preferably contact the interior surface of the lower end portion of
the
existing casing to form an fluid tight overlapping j oint. 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 j oint 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.
Alternatively, or in combiuation, a shock absorber is provided in the support
member 904 in order to absorb the shock caused by the sudden release of
pressure.
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Alternatively, or in combination, a mandrel catching structure is provided
above the support member 904 in order to catch or at least decelerate the
mandrel
906.
Once the extrusion process is completed, the mandre1906 is removed from
the wellbore. In a preferred embodiment, either before or after the removal of
the
mandre1906, the integrity of the fluidic seal of the overlapping joint between
the
upper portion of the tubular member 915 and the lower portion of the existing
casing is tested using conventional methods. If the fluidic seal of the
overlapping
joint between the upper portion of the tubular member 915 and the lower
portion
of the existing casing is satisfactory, then the uncured portion of any of the
hardenable fluidic sealing material within the expanded tubular member 915 is
then removed in a conventional manner. The hardenable fluidic sealing material
within the annular region between the expanded tubular member 915 and the
existing casing and new section of wellbore is then allowed to cure.
Preferably any remaining cured hardenable fluidic sealing material within
the interior of the expanded tubular members 902 and 915 is then removed in a
conventional manner using a conventional drill string. The resulting new
section
of casing preferably includes the expanded tubular members 902 and 915 and an
outer annular layer of cured hardenable fluidic sealing material. The bottom
portion of the apparatus 900 comprising the shoe 908 may then be removed by
drilling out the shoe 908 using conventional drilling methods.
In an alternative embodiment, during the extrusion process, it may be
necessary to remove the entire apparatus 900 from the interior of the wellbore
due
to a malfunction. In this circumstance, a conventional drill string is used to
drill
out the interior sections of the apparatus 900 in order to facilitate the
removal of
the remaining sections. In a preferred embodiment, the interior elements of
the
apparatus 900 are fabricated from materials such as, for example, cement and
aluminum, that permit a conventional drill string to be employed to drill out
the
interior components.
In particular, in a preferred embodiment, the composition of the interior
sections of the mandrel 906 and shoe 908, including one or more of the body of
cement 932, the spacer 938, the sealing sleeve 942, the upper cone retainer
944,
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the lubricator mandrel 946, the lubricator sleeve 948, the guide 950, the
housing
954, the body of cement 956, the sealin.g 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 wiIl now be described.
As
illustrated in Fig. 10a, a wellbore 1000 positioned in a subterranean
formation
1002 includes a first casing 1004 and a second casing 1006.
The first casing 1004 preferably includes a tubular liner 1008 and a cement
annulus 1010. The second casing 1006 preferably includes a tubular liner 1012
and a cement annulus 1014. In a preferred embodiment, the second casing 1006
is formed by expanding a tubular member substantially as described above with
reference to Figs. 1-9c or below with reference to Figs. lla-llf.
In a particularly preferred embodiment, an upper portion of the tubular
li.ner 1012 overlaps with a lower portion of the tubular liner 1008. In a
particularly
preferred embodiment, an outer surface of the upper portion of the tubular
liner
1012 includes one or more sealing members 1016 for providing a fluidic seal
between the tubular liners 1008 and 1012.
Referring to Fig. lOb, in order to create a tie-back liner that extends from
the overlap between the first aiid 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
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
. .,_ . __
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substantially as disclosed in U.S. Patent 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
mandrel 1105. - The tubular member 1105 is expanded in the radial direction
and
extruded off of the expandable mandrel 1105. The tubular member 1110 may be
fabricated from any number of materials such as, for example, Oilfield Country
Tubular Goods, 13 chromium tubing or plastic piping. In a preferred
embodiment,
the tubular member 1110 is fabricated from Oilfield Country Tubular Goods.
The inner and outer diameters of the tubular member 1110 may range, for
example, from approximately 0.75 to47 inches and 1.05 to 48 inches,
respectively.
In a preferred embodiment, the inner and outer diameters of the tubular member
1110 range from about 3 to 15.5 inches and 3.5 to 16 inches, respectively in
order
to optimally provide coverage for typical oilfield casing sizes. The tubular
member
1110 preferably comprises a solid member.
In a preferred embodiment, the upper end portion of the tubular member
1110 is slotted, perforated, or otherwise modified to catch or slow down the
maiidrel 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 tubulair member 1110
materials,
the length of the tubular member 1110 is preferably limited to between about
40
to 20,000 feet in length.
The shoe 1115 is coupled to the expandable mandrel 1105 and the tubular
member 1110. The shoe 1115 includes the fluid passage 1135. The shoe 1115 may
comprise any number of conventional commercially available shoes such as, for
example, Super Seal II float shoe, Super Seal II Down-Jet float shoe or a
guide shoe
with a sealing sleeve for a latch down plug modified in 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 alatch-
down
plug with side ports radiating off of the exit flow port available from
Halliburton
Energy Services in Dallas, TX, modified in accordance with the teachings of
the
present disclosure, in order to optimally guide the tubular member 1100 to the
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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 sealingmaterial into the region
outside the
shoe 1115 and tubular member 1110. In a preferred embodiment, the shoe 1115
includes one or more of the fluid passages 1140 each having an inlet geometry
that
can receive a dart and/or a ball sealing member. In this manner, the fluid
passages
1140 can be sealed off by introducing a plug, dart and/or ball sealing
elements into
the fluid passage 1130.
The cup seal 1120 is coupled to and supported by the support member 1150.
The cup seal 1120 prevents foreign materials from entering the interior region
of
the tubular member 1110 adjacent to the expandable mandrel 1105. The cup seal
1120 may comprise any number of conventional commercially available cup seals
such as, for example, TP cups or Selective Injection Packer (SIP) cups
modified in
accordance with the teachings of the present disclosure. In a preferred
embodiment, the cup seal 1120 comprises a SIP cup, available from Halliburton
Energy Services in Dallas, TX in order to optimally provide a barrier to
debris and
contain a body of lubricant.
The fluid passage 1130 permits fluidic material.s 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
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 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 tluid 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 ceinent, 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
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.
53
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The seals 1145 may comprise any number of conventional commercially
available seals such as, for example, lead, rubber, Teflon or epoxy seals
modified
in accordance with the teachings of the present disclosure. In a preferred
embodiment, the seals 1145 comprise seals molded from Stratalock epoxy
available
from Halliburton Energy Services in Dallas, TX in order to optimally provide a
hydraulic seal in the overlapping joint and optimally provide load carrying
capacity
to withstand the range of typical tensile and compressive loads.
In a preferred embodiment, the seals 1145 are selected to optimally provide
a sufficient frictional force to support the expanded tubular member 1110 from
the
tubular liner 1008. In a preferred embodiment, the frictional force provided
by the
seals 1145 ranges from about 1,000 to 1,000,0001bf in tension and compression
in
order to optimally support the expanded tubular member 1110.
The support member 1150 is coupled to the expandable mandrel 1105,
tubular member 1110, shoe 1115, and seal 1120. The support member 1150
preferably comprises an annular member having sufficient strength to carry the
apparatus 1100 into the wellbore 1000. In a preferred embodiment, the support
member 1150 further includes one or more conventional centralizers (not
illustrated) to help stabilize the tubular member 1110.
In a preferred embodiment, a quantity of lubricant 1150 is provided in the
annular region above the expandable mandrel 1105 withi.n 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. in Houston, TX in
order to optimally provide lubrication for the extrusion process.
In a preferred embodiment, the support member 1150 is thoroughly cleaned
prior to assembly to the remaining portions of the apparatus 1100. In this
manner, the introduction of foreign material into the apparatus 1100 is
minimized.
This minimizes the possibility of foreign material clogging the various flow
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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 PackerTM, EZ SV
PackerTM or a driIlable 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-backin 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. lOc, a hardenable fluidic sealing material 1160 is then
pumped from a surface location into the fluid passage 1130. The material 1160
then passes from the fluid passage 1130 into the interior region of the
tubular
niember 1110 below the expandable mandrel 1105. The materia11160 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 materia11160 causes the material
1160 to fill up at least a portion of the annular region.
The material 1160 may be pumped into the annular region at pressures and
flow rates ranging, for example, from about 0 to 5,000 psi and 0 to 1,500
gallons/m:in, respectively. In a preferred embodiment, the material 1160 is
pumped
into the annular region at pressures and flow rates specifically designed for
the
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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. 10d, once the annular region has been adequately filled
with material 1160, 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
mandrel 1105 causing the interior region to pressurize. In a particularly
preferred
embodiment, the one or more plugs 1165, or other similar devices, are
introduced
into the fluid passage 1140 with the introduction of the non hardenable
fluidic
material. In this manner, the amount of hardenable fluidic material within the
interior of the tubular member 1110 is minimized.
As illustrated in Fig. 10e, once the interior region becomes sufficiently
pressurized, the tubular member 1110 is extruded off of the expandable mandrel
1105. During the extrusion process, the expandable mandrel 1105 is raised out
of
the expanded portion of the tubular member 1110.
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The plugs 1165 are preferably placed into the fluid passages 1140 by
introducing the plugs 1165 into the fluid pa.ssage 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 approxiinately 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 below the
mandrel 1105 reaches approximately 1200 to 8500 psi.
During the extrusion process, the expandable mandrel 1105 may be raised
out of the expanded portion of the tubular member 1110 at rates ranging, for
example, from about 0 to 5 ft/sec. In a preferred embodiment, during the
extrusion
process, the expandable mandrel 1105 is raised out of the expanded portion of
the
tubular member 1110 at rates ranging from about 0 to 2 ft/sec in order to
optimally
provide permit adjustment of operational parameters, and optimally ensure that
the extrusion process will be completed before the material 1160 cures.
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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 mandrel 1105. In this manner, extrusion of the tubular member
1110 by the mandrel 1105 results in contact between substantially all of the
expanded tubular member 1110 and the existing casing 1008. In a preferred
embodiment, the contact pressure of the joint between the expanded tubular
member 1110 and the casings 1008 and 1012 ranges from about 500 to 10,000 psi
in order to optimally provide pressure to activate the sealing members 1145
and
provide optimal resistance to ensure that the joint will withstand typical
extremes
of tensile and compressive loads.
In a preferred embodiment, the operating pressure and flow rate of the
material 1161 is controllably ramped down when the expandable mandrel 1105
reaches the upper end portion of the tubular member 1110. In this manner, the
sudden release of pressure caused by the complete extrusion of the tubular
member 1110 off of the expandable mandrel 1105 can be minimized. In a
preferred emboditnent, the operating pressure of the fluidic material 1161 is
reduced in a substantially linear fashion from 100% to about 10% during the
end
of the extrusion process beginning when the mandrel 1105 has completed
approximately all but about 5 feet of the extrusion process.
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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
liner
of casing 1170 includes the expanded tubular member 1110 and an outer annular
layer 1175 of cured material 1160.
As illustrated in Fig. lOg, the remaining bottom portion of the apparatus
1100 comprising the shoe 1115 and packer 1155 is then preferably removed by
drilling out the shoe 1115 and packer 1155 using conventional drilling
methods.
In a particularly preferred embodiment, the apparatus 1100 incorporates
the apparatus 900.
Referring now to Figs. lla-11f, an embodiment of an apparatus and method
for hanging a tubular liner off of an existing wellbore casing will now be
described.
As illustrated in Fig. lla, a wellbore 1200 is positioned in a subterranean
formation 1205. The wellbore 1200 includes an existing cased section 1210
having
a tubular casing 1215 and an annular outer layer of cement 1220.
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In order to extend the weUbore 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. Patent 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 maybe fabricated from any number of materials such as, for example,
Oilfield
Country Tubular Goods (OCTG), 13 chromium steel tubing/casing or plastic
casing. In a preferred embodiment, the tubular member 1310 is fabricated from
OCTG. The inner and outer diameters of the tubular member 1310 may range, for
example, from approximately 0.75 to 47 inches and 1.05 to 48 inches,
respectively.
In a preferred embodiment, the inner and outer diameters of the tubular member
1310 range from about 3 to 15.5 inches and 3.5 to 16 inches, respectively in
order
to optimally provide minimal telescoping effect in the most commonly
encountered
wellbore sizes.
In a preferred embodiment, the tubular member 1310 includes an upper
portion 1355, an intermediate portion 1360, and a lower portion 1365. In a
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preferred embodiment, the wall thickness and outer diameter of the upper
portion
1355 of the tubular member 1310 range from about 3/8 to 1V2inches and 3;/2 to
16 inches, respectively. In a preferred embodiment, the wall thickness and
outer
diameter of the intermediate portion 1360 of the tubular member 1310 range
from
about 0.625 to 0.75 inches and 3 to 19 inches, respectively. In a preferred
embodiment, the wall thickness and outer diameter of the lower portion 1365 of
the tubular member 1310 range from about 3/8 to 1.5 inches and 3.5 to 16
inches,
respectively.
In a particularly preferred embodiment, the outer diameter of the lower
portion 1365 of the tubular member 1310 is significantly less than the outer
diameters of the upper and intermediate portions, 1355 and 1360, of the
tubular
member 1310 in order to optimize the formation of a concentric and overlapping
arrangement of wellbore casings. In this manner, as will be described below
with
reference to Figs. 12 and 13, a wellhead system is optimally provided. In a
preferred embodiment, the formation of a wellhead system does not include the
use
of a hardenable fluidic material.
In a particularly preferred embodiment, the wall thickness of the
intermediate section 1360 of the tubular member 1310 is less than or equal to
the
wall thickness of the upper and lower sections, 1355 and 1365, of the tubular
member 1310 in order to optimally faciliate the initiation of the extrusion
process
and optimally permit the placement of the apparatus in areas of the wellbore
having tight clearances.
The tubular member 1310 preferably comprises a solid member. In a
preferred embodiment, the upper end portion 1355 of the tubular member 1310
is slotted, perforated, or otherwise modified to catch or slow down the
mandrel
1305 when it completes the extrusion of tubular member 1310. In a preferred
embodiment, the length of the tubular member 1310 is limited to minimiae the
possibility of buckling. For typical tubular member 1310 materials, the length
of
the tubular member 1310 is preferably limited to between about 40 to 20,000
feet
in length.
The shoe 1315 is coupled to the tubular member 1310. The shoe 1315
preferably includes fluid passages 1330 and 1335. The shoe 1315 may comprise
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any number of conventional commercially available shoes such as, for example,
Super Seal II float shoe, Super Seal II Down-Jet float shoe or guide shoe with
a
sealing sleeve for a latch-down plug modified in accordance with the teachings
of
the present disclosure. In a preferred embodiment, the shoe 1315 comprises an
aluminum down-jet guide shoe with a sealing sleeve for a latch-down plug
available
from Halliburton Energy Services in Dallas, TX, modified in accordance with
the
teachings of the present disclosure, in order to optimally guide the tubular
member
1310 into the wellbore 1200, optimally fluidicly isolate the interior of the
tubular
member 1310, and optimally permit the complete driIl 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
man.ner,
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 centerline of the apparatus 1300. The fluid passage 1320 is preferably
selected
to transport materials such as cement, drilling mud, or epoxies at flow rates
and
pressures ranging from about 0 to 3,000 gallons/minute and 0 to 9,000 psi in
order
to optimally provide sufficient operating pressures to circulate fluids at
operationally efficient rates.
The fluid passage 1330 permits fluidic materials to be transported to and
from the region exterior to the tubular member 1310 and shoe 1315. The fluid
passage 1330 is coupled to and positioned within the shoe 1315 in fluidic
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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 intl-oduci.ng a
plug, dart
and/or ball sealing elements into the fluid passage 1320.
The fluid passage 1335 permits fluidic materials to be transported to and
from the region exterior to the tubular member 1310 and shoe 1315. The fluid
passage 1335 is coupled to and positioned within the shoe 1315 in fluidic
communication with the fluid passage 1330. The fluid passage 1335 is
preferably
positioned substantially along the centerline of the apparatus 1300. The fluid
passage 1335 is preferably selected to convey materials such as cement,
drilling
mud or epoxies at flow rates and pressures ranging from about 0 to 3,000
gallons/minute and 0 to 9,000 psi in order to optimally fill the annular
region
between the tubular member 1310 and the new section 1230 of the wellbore 1200
with fluidic materials.
The seals 1340 are coupled to and supported by the upper end portion 1355
of the tubular member 1310. The seals 1340 are further positioned on an outer
surface of the upper end portion 1355 of the tubular member 1310. The seals
1340
permit the overlapping joint between the lower end portion of the casing 1215
and
the upper portion 1355 of the tubular member 1310 to be fluidicly sealed. The
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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 j oint 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
three-wiper latch-down plug modified in accordance with the teachinggs of the
present disclosure. In a preferred embodiment, the wiper plug 1350 comprises a
Multiple Stage Cementer latch-down plug available from Halliburton Energy
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Services in Dallas, TX modified in a conventional manner for releasable
attachment to the expansion mandrel 1305.
In a preferred embodiment, before or after positioning the apparatus 1300
within the new section 1230 of the wellbore 1200, a couple of wellbore volumes
are
circulated in order to ensure that no foreign materials are located within the
wellbore 1200 that might clog up the various flow passages and valves of the
apparatus 1300 and to ensure that no foreign material interferes with the
extrusion process_
As illustrated in Fig. 11c, a hardenable fluidic sealing material 1380 is then
pumped from a surface location into the fluid passage 1320. The material 1380
then passes from the fluid passage 1320, through the fluid passage 1375, 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 fiIls 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 material 1380 to fill
up
at least a portion of the annular region 1390.
The material 1380 may be pumped into the annular region 1390 at
pressures and flow rates ranging, for example, from about 0 to 5000 psi and 0
to
1,500 gallons/min, respectively. In a preferred embodiment, the material 1380
is
pumped into the annular region 1390 at pressures and flow rates ranging from
about 0 to 5000 psi and 0 to 1,500 gallons/min, respectively, in order to
optimally
fill the annular region between the tubular member 1310 and the new section
1230
of the wellbore 1200 with the hardenable fluidic sealing material 1380.
The hardenable fluidic sealing material 1380 may comprise any number of
conventional commercially available hardenable fluidic sealing materials such
as,
for example, slag mi.x, cement or epoxy. In a preferred embodiment, the
hardenable fluidic sealing material 1380 comprises blended cements designed
specificallyfor the well section being drilled and available from Halliburton
Energy
Services in order to optimally provide support for the tubular member 1310
during
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displacement of the materia11380 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 mandrel 1305. The wiper dart 1395 and wiper plug 1350 then preferably
will lodge in the fluid passage 1330, thereby blocking fluid flow through the
fluid
passage 1330, and fluidicly isolating the interior region 1370 of the tubular
member 1310 from the annular region 1390. In a preferred embodiment, the non
hardenable fluidic material 1381 is then pumped into the interior region 1370
causing the interior region 1370 to pressurize. Once the interior region 1370
becomes sufficiently pressurized, the tubular member 1310 is extruded off of
the
expandable mandrel 1305. During the extrusion process, the expandable mandrel
1305 is raised out of the exparided portion of the tubular member 1310 by the
support member 1345.
The wiper dart 1395 is preferably placed into the fluid passage 1320 by
introducing the wiper dart 1395 into the fluid passage 1320 at a surface
location
in a conventional manner. The wiper dart 1395 may comprise any number of
conventional commercially available devices from plugging a fluid passage such
as,
for example, Multiple Stage Cementer latch-down plugs, Omega latch-down plugs
or three wiper latch-down plug/dart modified in accordance with the teachings
of
the present disclosure. In a preferred embodiment, the wiper dart 1395
comprises
a three wiper latch-down plug modified to latch and seal in the Multiple Stage
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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 material 1381 is preferably pumped into the interior region
1370 at pressures and flow rates ranging from approximately 500 to 9,000 psi
and
40 to 3,000 gallons/min in order to optimally provide operating pressures to
maintain the expansion process at rates sufficient to permit adjustments to be
made in operating parameters during the extrusion process.
For typical tubular members 1310, the extrusion of the tubular member
1310 off of the expandable mandrel 1305 will begin when the pressure of the
interior region 1370 reaches, for example, approximately 500 to 9,000 psi. In
a
preferred embodiment, the extrusion of the tubular member 1310 off of the
expandable mandrel 1305 is a function of the tubular member diameter, wall
thickness of the tubular member, geometry of the mandrel, the type of
lubricant,
the composition of the shoe and tubular member, and the yield strength of the
tubular member. The optimum flow rate and operating pressures are preferably
determined using conventional empirical methods.
During the extrusion process, the expandable mandrel 1305 may be raised
out of the expanded portion of the tubular member 1310 at rates ranging, for
example, from about 0 to 5 ft/sec. In a preferred embodiment, during the
extrusion
process, the expandable mandrel 1305 may be raised out of the expanded portion
of the tubular member 1310 at rates ranging from about 0 to 2 ft/sec in order
to
optimally provide an efficient process, optimally permit operator adjustment
of
operation parameters, and ensure optimal completion of the extrusion process
before curing of the material 1380.
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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 material 1381.is controllably ramped down when the
expandable
mandrel 1305 reaches the upper end portion 1355 of the tubular member 1310.
In this manner, the sudden release of pressure caused by the complete
extrusion
of the tubular member 1310 off of the expandable mandrel 1305 can be
minimized.
In a preferred embodiment, the operating pressure is reduced in a
substantially
linear fashion from 100% to about 10% during the end of the extrusion process
beginning when the mandrel 1305 has completed approxiunately all but about 5
feet of the extrusion process.
Alternatively, or in combination, a shock absorber is provided in the support
member 1345 in order to absorb the shock caused by the sudden release of
pressure.
Alternatively, or in combination, a mandrel catching structure is provided
in the upper end portion 1355 of the tubular member 1310 in order to catch or
at
least decelerate the mandrel 1305.
Once the extrusion process is completed, the expandable mandrel 1305 is
removed from the wellbore 1200. In a preferred embodiment, either before or
after
the removal of the expandable mandrel 1305, the integrity of the fluidic seal
of the
overlapping joint between the upper portion 1355 of the tubular member 1310
and
the lower portion of the casing 1215 is tested using conventional methods. If
the
fluidic seal of the overlapping joint between the upper portion 1355 of the
tubular
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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 man.ner. The material 1380 within the
annular
region 1390 is then allowed to cure.
As illustrated in Fig. Llf, preferably any remaining cured material 1380
within the interior of the expanded tubular member 1310 is then removed in a
conventional manner using a conventional drill string. The resulting new
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 weIlhead
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 SystemTM, Spool Tree Subsea Production SystemTM or the
Compact Wellhead SystemTM available from suppliers such as Dril-Quip, Cameron
or
Breda, modified in accordance with the teachings of the present disclosure.
The
drilling spool assembly 1505 is preferably operably coupled to the thick wall
casing
1510 and/or the outer casing 1520. The assembly 1505 may be coupled to the
thick
wall casing 1510 and/or outer casing 1520, for example, by welding, a threaded
connection or made from single stock. In a preferred embodiment, the assembly
1505 is coupled to the thick wall casing 1510 and/or outer casing 1520 by
welding.
The thick wall casing 1510 is positioned in the upper end of a wellbore 1540.
In a preferred embodiment, at least a portion of the thick wall casing 1510
extends
above the surface 1545 in order to optimally provide easy access and
attachment
to the Christmas tree/drilling spool assembly 1505. The thick wall casing 1510
is
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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 CountryTubular Goods
available from various foreign and domestic steel mills. In a preferred
embodiment, the thick wall casing 1510 has a yield strength of about 40,000 to
135,000 psi in order to optimally provide maximum burst, collapse, and tensile
strengths. In a preferred embodiment, the thick wall casing 1510 has a failure
strength in excess of about 5,000 to 20,000 psi in order to optimally provide
maximum operating capacity and resistance to degradation of capacity after
being
drilled through for an extended time period.
The annular body of cement 1515 provides support for the thick wall casing
1510. The annular body of cement 1515 may be provided using any number of
conventional processes for forming an annular body of cement in a wellbore.
The
annular body of cement 1515 may comprise any number of conventional cement
mixtures.
The outer casing 1520 is coupled to the thick wall casing 1510. The outer
casing 1520 may be fabricated from any number of conventional commercially
available tubular members modified in accordance with the teachings of the
present disclosure. In a preferred embodiment, the outer casing 1520 comprises
any one of the expandable tubular members described above with reference to
Figs. 1- l lf.
In a preferred embodiment, the outer casing 1520 is coupled to the thick
wall casing 1510 by expanding the outer casing 1520 into contact with at least
a
portion of the interior surface of the thick wall casing 1510 using any one of
the
embodiments of the processes and apparatus described above with reference to
Figs. 1-llf. In an alternative embodiment, substantially all of the overlap of
the
outer casing 1520 with the thick wall casing 1510 contacts with the interior
surface
of the thick wall casing 1510.
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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 driIling and production
operations.
As illustrated in Fig. 13, in a particularly preferred embodiment, the upper
end of the outer casing 1520 includes one or more sealing members 1550 that
provide a gaseous and fluidic seal between the expanded outer casing 1520 and
the
interior wall of the thick waU casing 1510. The sealing members 1550 may
comprise any number of conventional commercially available seals such as, for
example, lead, plastic, rubber, Teflon or epoxy, modified in accordance with
the
teachings of the present disclosure. In a preferred embodiment, the sealing
members 1550 comprise seals molded from StrataLock epoxy available from
Halliburton Energy Services in order to optimally provide an hydraulic seal
and
a load bearing interference fit between the tubular members. In a preferred
embodiment, the contact pressure of the interface between the thick wall
casing
1510 and the outer casing 1520 ranges from about 500 to 10,000 psi in order to
optimally activate the sealing members 1550 and also optimally ensure that the
joint will withstand the typical operating extremes oftensile and compressive
loads
during drilling and production operations.
In an alternative preferred embodiment, the outer casing 1520 and the thick
walled casing 1510 are combined in one unitary member.
The annular body of cement 1525 provides support for the outer casing
1520. In a preferred embodiment, the annular body of cement 1525 is provided
using any one of the embodiments of the apparatus and processes described
above
with reference to Figs. 1-1 lf.
The intermediate casing 1530 may be coupled to the outer casing 1520 or
the thick wall casing 1510. In a preferred embodiment, the intermediate casing
1530 is coupled to the thick wall casing 1510. The intermediate casing 1530
may
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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-llf.
In a preferred embodiment, the intermediate casing 1530 is coupled to the
thick wall casing 1510 by expanding at least a portion of the intermediate
casing
1530 into contact with the interior surface of the thick wall casing 1510
using any
one of the processes and apparatus described above with reference to Figs. 1-
llf.
In an alternative preferred embodiment, the entire length of the overlap of
the
intermediate casing 1530 with the thick wall casing 1510 contacts the inner
surface of the thick wall casing 1510. The contact pressure of the interface
between the intermediate casing 1530 and the thick wall casing 1510 may range,
for example from about 500 to 10,000 psi. In a preferred embodiment, the
contact
pressure between the intermediate casing 1530 and the thick wall casing 1510
ranges from about 500 to 10,000 psi in order to optimally activate the
pressure
activated sealing members and to optimally ensure that the joint will
withstand
typical operating extremes of tensile and compressive loads experienced during
drilling and production operations.
As illustrated in Fig. 13, in a particularly preferred embodiment, the upper
end of the intermediate casing 1530 includes one or more sealing members 1560
that provide a gaseous and fluidic seal between the expanded end of the
intermediate casing 1530 and the interior wall of the thick wall casing 1510.
The
sealing members 1560 may comprise any number of conventional commercially
available seals such as, for example, plastic, lead, rubber, Teflon or epoxy,
modified
in accordance with the teachings of the present disclosure. In a preferred
embodiment, the sealing members 1560 comprise seals molded from StrataLock
epoxy available from Halliburton Energy Services in order to optimally provide
a
hydraulic seal and a load bearing interference fit between the tubular
members.
In a preferred embodiment, the contact pressure of the interface between
the expanded end of the intermediate casing 1530 and the thick wall casing
1510
ranges from about 500 to 10,000 psi in order to optimally activate the sealing
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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-llf.
In a preferred embodiment, the inner casing 1535 is coupled to the outer
casing 1520 by expanding at least a portion of the inner casing 1535 into
contact
with the interior surface of the thick wall casing 1510 using any one of the
processes and apparatus described above with reference to Figs. 1-11f. 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 siurfaces 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 thejoint will
withstand
typical extremes of tensile and compressive loads that are commonly
experienced
during drilling and production operations.
As iIlustrated in Fig. 13, in a particularly preferred embodiment, the upper
end of the inner casing 1535 includes one or more sealing members 1570 that
provide a gaseous and fluidic seal between the expanded end of the inner
casing
1535 and the interior wall of the thick wall casing 1510. The sealing members
1570 may comprise any number of conventional commercially available seals such
as, for example, lead, plastic, rubber, Teflon or epoxy, modified in
accordance with
the teachings of the present disclosure. In a preferred embodiment, the
sealing
members 1570 comprise seals molded from StrataLock epoxy available from
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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 drilli.ng and production operations.
In an alternative embodiment, the inner casings, 1520, 1530 and 1535, may
be coupled to a previously positioned tubular member that is in turn coupled
to the
outer casing 1510. More generally, the present preferred embodiments may be
used to form a concentric arrangement of tubular members.
Referring now to Figures 14a, 14b, 14c, 14d, 14e and 14f, a preferred
embodiment of a method and apparatus for forming a mono-diameter well casing
within a subterranean formation will now be described.
As illustrated in Fig. 14a, a wellbore 1600 is positioned in a subterranean
formation 1605. A first section of casing 1610 is formed in the wellbore 1600.
The
first section of casing 1610 includes an annular outer body of cement 1615 and
a
tubular section of casing 1620. The first section of casing 1610 may be formed
in
the wellbore 1600 using conventional methods and apparatus. In a preferred
embodiment, the first section of casing 1610 is formed using one or more of
the
methods and apparatus described above with reference to Figs. 1-13 or below
with
reference to Figs. 14b-17b.
The annular body of cement 1615 may comprise any number of conventional
commercially available cement, or other load bearing, compositions.
Alternatively,
the body of cement 1615 may be omitted or replaced with an epoxy mixture.
The tubular section of casing 1620 preferably includes an upper end 1625
and a lower end 1630. Preferably, the lower end 1625 of the tubular section of
casing 1620 includes an outer annular recess 1635 extending from the lower end
1630 of the tubular section of casing 1620. In this manner, the lower end 1625
of
the tubular section of casing 1620 includes a thin walled section 1640. In a
preferred embodiment, an annular body 1645 of a compressible material is
coupled
to and at least partially positioned within the outer annular recess 1635. In
this
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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 minimizingresistance to radial expansion. The axial
length
of the thin walled section 1640 may range from about 120 to 2400 inches. In a
preferred embodiment, the axial length of the thin walled section 1640 ranges
from
about 240 to 480 inches.
The annular body of compressible material 1645 helps to minimize the
radial force required to expand the tubular casing 1620 in the overlap with
the
tubular member 1715, helps to create a fluidic seal in the overlap with the
tubular
member 1715, and helps to create an interference fit sufficient to permit the
tubular member 1715 to be supported by the tubular casing 1620. The annular
body of compressible material 1645 may comprise any number of commercially
available compressible materials such as, for example, epoxy, rubber, Teflon,
plastics or lead tubes. In a preferred embodiment, the annular body of
compressible material 1645 comprises StrataLock epoxy available from
Halliburton Energy Services in order to optimally provide an hydraulic seal in
the
overlapped joint while also having compliance to thereby minimize the radial
force
required to expand the tubular casing. The wall thickness of the annular body
of
compressible material 1645 may range from about 0.05 to 0.75 inches. In a
preferred embodiment, the wall thickness of the annular body of compressible
material 1645 ranges from about 0.1 to 0.5 inches in order to optimally
provide a
large compressible zone, minimize the radial forces required to expand the
tubular
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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
supporting the mandrel 1710 when the pressure chamber 1755 is unpressurized.
The mandrel 1710 is supported by and slidingly coupled to the support
member 1705 and the shoe 1720. The mandrel 1710 preferably includes an upper
portion 1760 and a lower portion 1765. Preferably, the upper portion 1760 of
the
mandrel 1710 and the support member 1705 together define the pressure chamber
1755. Preferably, the lower portion 1765 of the mandrel 1710 includes an
expansion member 1770 for radially expanding the tubular member 1715.
In a preferred embodiment, the upper portion 1760 of the mandrel 1710
includes a tubular member 1775 having an inner diameter greater than an outer
diameter of the support member 1705. In this manner, an annular pressure
chamber 1755 is defined by and positioned between the tubular member 1775 and
the support member 1705. The top 1780 of the tubular member 1775 preferably
includes a bearing and a seal for sealing and supporting the top 1780 of the
tubular
member 1775 against the outer surface of the support member 1705. The bottom
1785 of the tubular member 1775 preferably includes a bearing and seal for
sealing
and supporting the bottom 1785 of the tubular member 1775 against the outer
surface of the support member 1705 or shoe 1720. In this manner, the mandrel
1710 moves in an axial direction upon the pressurization of the pressure
chamber
1755.
The lower portion 1765 of the mandrel 1710 preferably includes an
expansion member 1770 for radially expanding the tubular member 1715 during
the pressurization of the pressure chamber 1755. In a preferred embodiment,
the
expansion member is expandable 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 opt,unally 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 tbin walled section 1815. The second
compressible annular member 1750 is coupled to and at least partially
supported
within the outer annular recess 1810 of the upper portion 1790 of the tubular
member 1715 in opposing relation to the thin wall section 1815.
The tubular member 1715 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, stainless steel, low alloy steel, carbon steel,
automotive
grade steel, fiberglass, 13 chrome steel, other high strength material, or
high
strength plastics. In a preferred embodiment, the tubular member 1715 is
fabricated from oilfield country tubular goods available from various foreign
and
domestic steel mills in order to optimally provide operational strength.
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, RTTSTM packer tungsten carbide
mechanical slips,
RTTS packer wicker type mechanical slips, or Model 3LTM 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 mi.nimize
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 m.inimizes 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 fiIls 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, driIling mud or driIling gases in order
to
optimally provide pressurization of the pressure chamber 1755.
The fluidic material 1840 may be pumped into the fluid passage 1730 at
operating pressures and flow rates ranging, for example, from about 0 to 9,000
psi
and 0 to 500 gallons/minute. In a preferred embodiment, the fluidic material
1840
is pumped into the fluid passage 1730 at operating pressures and flow rates
ranging from about 500 to 5,000 psi and 0 to 500 gallons/minute in order to
optimally provide operating pressures and flow rates for radial expansion.
The fluidic material 1840 pumped into the fluid passage 1730 passes
through the fluid passages 1735 and into the pressure chamber 1755. Continued
pumping of the fluidic material 1840 pressurizes the pressure chamber 1755.
The
pressurization of the pressure chamber 1755 causes the mandrel 1710 to move
relative to the support member 1705 in the direction 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 -r-,nirt,ize 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
perniit
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
and the pressure chamber 1755.
As illustrated in Fig. 14f, in a preferred embodiment, once the tubular
member 1715 is completely expanded in the radial direction by the mandrel
1710,
the support member 1705 and mandrel 1710 are removed from the wellbore 1600.
In a preferred embodiment, the annular body of hardenable fluidic material is
then
allowed to cure to form a rigid outer annular body 1850. In the case where the
tubular member 1715 is slotted, the hardenable fluidic material will
preferably
permeate and envelop the expanded tubular member 1715.
The resulting new section of wellbore casing 1855 includes the expanded
tubular member 1715 and the rigid outer annular body 1850. The overlapping
joint 1860 between the tubular casing 1620 and the expanded tubular member
1715 includes the deformed thin wall sections, 1640 and 1805, and the
compressible annular bodies, 1645 and 1745. The inner diameter of the
resulting
combined wellbore casings is substantially constant_ In this manner, a mono-
diameter wellbore casing is formed. This process of expanding overlapping
tubular
members having thin wall end portions with compressible annular bodies into
contact can be repeated for the entire length of a wellbore. 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 sealingmandre11935, 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, driIlpipe connectors, OCTGTM
specialty
type box and pin connectors, a ratchet-latch type connector or a standard box
by
pin connector. In a preferred embodiment, the drillpipe 1905 is removably
coupled
to the innerstring adapter 1910 by a drillpipe connection.
The drillpipe 1905 preferably includes a fluid passage 1975 that is adapted
to convey fluidic materials from a surface location into the fluid passage
1980. In
a preferred embodiment, the fluid passage 1975 is adapted to convey fluidic
materials such as, for example, cement, drilling mud, epoxy or lubricants at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to
3,000
gallons/minute.
The innerstring adapter 1910 is coupled to the drill string 1905 and the
sealing sleeve 1915. The innerstring adapter 1910 preferably comprises a
substantially hollow tubular member or members. The innerstring adapter 1910
may be fabricated from any number of conventional commercially available
materials such as, for example, oil country tubular goods, low alloy steel,
carbon
steel, stainless steel or other high strength materials. In a preferred
embodiment,
the innerstring adapter 1910 is fabricated from oilfield country tubular goods
in
order to optimally provide mechanical properties that closely match those of
the
drill string 1905.
The innerstring adapter 1910 may be coupled to the drill string 1905 using
any number of conventional commercially available mechanical couplings such
as,
for example, drillpipe connectors, oilfield country tubular goods specialty
type
threaded connectors, ratchet-latch type stab in connector, or a standard
threaded
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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, drilipipe
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
optamally 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 mandrel 1920 by a standard threaded connection.
The sealing sleeve 1915 preferably includes a fluid passage 1985 that is
adapted to convey fluidic materials from the fluid passage 1980 into the fluid
passage 1990. In a preferred embodiment, the fluid passage 1985 is adapted to
convey fluidic materials such as, for example, cement, drilling mud, epoxy or
lubricants at operating pressures and flow rates ranging from about 0 to 9,000
psi
and 0 to 3,000 gallons/minute.
The inner sealing mandrel 1920 is coupled to the sealing sleeve 1915 and the
lower sealing head 1930. The inner sealing mandrel 1920 preferably comprises a
substantially hollow tubular member or members. The inner sealing mandre11920
may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, stainless
steel, low
alloy steel, carbon steel or other similar high strength materials. In a
preferred
embodiment, the inner sealing mandrel 1920 is fabricated from stainless steel
in
order to optimally provide mechanical properties similar to the other
components
of the apparatus 1900 wbile 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 mandre11920 may be coupled to the sealing sleeve 1915,
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty
type threaded connection, or a standard threaded connection . In a preferred
embodiment, the inner sealing mandrel 1920 is removably coupled to the sealing
sleeve 1915 by a standard threaded connections. The inner sealing mandrel 1920
may be coupled to the lower sealing head 1930 using any number of conventional
conunercially available mechanical couplings such as, for example, drillpipe
connection, oilfield country tubular goods specialty type threaded connection,
ratchet-latch type stab in connectors or standard threaded connections. In a
preferred embodiment, the inner sealing mandrel 1920 is removably coupled to
the
lower sealing head 1930 by a standard threaded connections connection.
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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 mandrel 1935
and the expansion cone 1945. The upper sealing head 1925 is also movably
coupled to the outer surface of the inner sealing mandrel 1920 and the inner
surface of the casing 1970. In this manner, the upper sealing head 1925, outer
sealing mandrel 1935, and the expansion cone 1945 reciprocate in the axial
direction. The radial clearance between the inner cylindrical surface of the
upper
sealing head 1925 and the outer surface of the inner sealing mandrel 1920 may
range, for example, from about 0.025 to 0.05 inches. In a preferred
embodiment,
the radial clearance between the inner cylindrical surface of the upper
sealing head
1925 and the outer surface of the inner sealing mandrel 1920 ranges from about
0.005 to 0.01 inches in order to optimally provide clearance for pressure seal
placement. The radial clearance between the outer cylindrical surface of the
upper
sealing head 1925 atid 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, oilfleld 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, polypakTM 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 uppei= 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 mandrel 1935. The sealing members 2010 may comprise any number of
conventional commercially available sealing members such as, for example, o-
rings,
polypak seals or metal spring energized seals. In a preferred embodiment, the
sealing members 2010 comprise polypak seals ava.ilable 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 seali.ng mandrel 1935 reciprocate in the axial
direction. The radial clearance between the outer surface of the lower sealing
head 1930 and the inner surface of the outer sealing mandrel 1935 may range,
for
example, from aboutØ025 to 0.05 inches. In a preferred embodiment, the
radial
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clearance between the outer surface of the lower sealing head 1930 and the
inner
surface of the outer sealing mandrel 1935 ranges from about 0.005 to 0.010
inches
in order to optimally provide a close tolerance having room for the
installation of
pressure seal rings.
The lower sealing head 1930' preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The lower sealing
head
1930 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, stainless
steel,
machine tool steel or other similar high strength materials. In a preferred
embodiment, the lower sealing head 1930 is fabricated from stainless steel in
order
to optimally provide high strength and resistance to wear, galling, corrosion,
and
pitting.
The outer surface of the lower sealing head 1930 preferably includes one or
more annular sealing members 2015 for sealing the interface between the lower
sealing head 1930 and the outer sealing mandrel 1935. The sealing members 2015
may comprise any number of conventional commercially available annular sealing
members such as, for example, o-rings, polypak seals, or metal spring
energized
seals. In a preferred embodiment, the sealing members 2015 comprise polypak
seals available from Parker Seals in order to optimally provide sealing for a
long
axial stroke.
The lower sealing head 1930 may be coupled to the inner sealing mandrel
1920 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods
specialty type threaded connection, welding, amorphous bonding or a standard
threaded connection. In a preferred embodiment, the lower sealing head 1930 is
removably coupled to the inner sealing mandrel 1920 by a standard threaded
connection.
In a preferred embodiment, the mechanical coupling between the lower
sealing head 1930 and the inner sealing mandrel 1920 includes one or more
sealing
members 2020 for fluidicly sealing the interface between the lower sealing
head
1930 and the inner sealing mandrel 1920. The sealing members 2020 may
comprise any number of conventional commercially available sealing members
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such as, for example, o-rings, polypak seals, or metal spring energized seals.
In a
preferred embodiment, the sealing members 2020 comprise polypak seals
available
from Parker Seals in order to optimally provide sealing for a long axial
motion.
The lower sealing head 1930 may be coupled to the load mandrel 1940 using
any number of conventional commercially available mechanical couplings such
as,
for example, drillpipe connection, oilfield country tubular goods specialty
type
threaded connections, welding, amorphous bonding or a standard threaded
connection. In a preferred embodiment, the lower sealing head 1930 is
removably
coupled to the load mandrel 1940 by a standard threaded connection. In a
preferred embodiment, the mechanical coupling between the lower sealing head
1930 and the load mandrel 1940 includes one or more sealing members 2025 for
fluidicly sealing the interface between the lower sealing head 1930 and the
load
mandrel 1940. The sealing members 2025 may comprise any number of
conventional commerciallyavailable sealingmembers such as, for example, o-
rings,
polypak seals, or metal spring energized seals. In a preferred embodiment, the
seali.ng 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 mandrel 1935
and
the inner surface of the casing 1970 may range, for example, from about 0.025
to
0.375 inches. In a preferred embodiment, the radial clearance between the
outer
surface of the outer sealing mandrel 1935 and the inner surface of the casing
1970
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ranges from about 0.025 to 0.125 inches in order to optimally provide maximum
piston surface area to maximize the radial expansion force. The radial
clearance
between the inner surface of the outer sealing mandre11935 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 mandre11935 is removably coupled to
the upper sealing head 1925 by a standard threaded connections connection. The
outer sealing mandrel 1935 may be coupled to the expansion cone 1945 using any
number of conventional commercially available mechanical couplings such as,
for
example, drillpipe connection, oilfield country tubular goods specialty type
threaded connection, or a standard threaded connections connection, or
welding.
In a preferred embodiment, the outer sealing mandrel 1935 is removably coupled
to the expansion cone 1945 by a standard threaded connections connection.
The upper sealing head 1925, the lower sealing head 1930, the inner sealing
mandrel 1920, and the outer sealing mandrel 1935 together define a pressure
chamber 2030. The pressure chamber 2030 is fluidicly coupled to the passage
1990
via one or more passages 2035. During operation of the apparatus 1900, the
plug
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2045 engages with the throat passage 2040 to fluidicly isolate the fluid
passage
1990 from the fluid passage 1995. The pressure chamber 2030 is then
pressurized
which in turn causes the upper seali.ng head 1925, outer sealing mandre11935,
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 sim.ilar 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 mandre11940 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 coupli.ngs 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 seali.ng mandre11935- 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, gaIling, 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 example, drillpipe connection, oilfleld 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 waIl thickness of the mandrel launcher 1950 ranges
from about 0.25 to 0.75 inches in order to optimally provide high strength
with a
small overall profile. The mandrel launcher 1950 may be fabricated from any
number of conventional commercially available materials such as, for example,
oil
field tubular goods, low alloy steel, carbon steel, stainless steel or other
similar
high strength materials. In a preferred embodiment, the mandrel launcher 1950
is fabricated from oil field tubular goods of higher strength but lower wall
thickness than the casing 1970 in order to optimally provide a thin walled
container with approximately the same burst strength as the casing 1970.
The mechanical slip body 1955 is coupled to the load mandrel 1970, the
mechanical slips 1960, and the drag blocks 1965. The mechanical slip body 1955
preferably comprises a tubular member having an inner passage 2050 fluidicly
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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
mandrel 1940 using a standard threaded connection in order to optimally
provide
high strength and permit the mechanical slip body 1955 to be easily replaced.
The
mechanical slip body 1955 may be coupled to the mechanical slips 1955 using
any
number of conventional mechanical couplings. In a preferred embodiment, the
mechanical slip body 1955 is removably coupled to the mechanical slips 1955
using
threads and sliding steel retainer rings in order to 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/m.inute 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 driIl string 1905 is raised. This causes
the inner
sealing mandre11920, lower sealing head 1930, load mandrel 1940, and
mechanical
slip body 1955 to move upward. This unsets the mechanical slips 1960 and
permits
the mechanical slips 1960 and drag blocks 1965 to be moved upward within the
mandrel launcher and casing 1970. When the lower sealing head 1930 contacts
the
upper sealing head 1925, the second fluidic material is again pressurized and
the
radial expansion process continues. In this manner, the mandrel launcher 1950
and casing 1970 are radial expanded through repeated axial strokes of the
upper
sealing head 1925, outer sealing mandrel 1935 and expansion cone 1945.
Throughput the radial expansion process, the upper end of the casing 1970 is
preferably maintained in an overlapping relation with an existing section of
wellbore casing.
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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 apreferred 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 wellbore casing is formed within a wellbore. Alternatively, the
apparatus 1900 may be used to join a first section of pipeline to an existing
section
of pipeline. Alternatively, the apparatus 1900 may be used to 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 1975, 1980, 1985, and 1990, and the
pressure
chamber 2030. No fluid pressure acts directly on the mandrel launcher 1950 and
casing 1970. This permits the use of operating pressures higher than the
mandrel
launcher 1950 and casing 1970 could normally withstand_
Referring now to Figure 16, a preferred embodiment of an apparatus 2100
for forming a mono-diameter wellbore casing will be described. The apparatus
2100 preferably includes a drillpipe 2105, an innerstring adapter 2110, a
sealing
sleeve 2115, an inner sealing 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.
The drillpipe 2105 preferably comprises a substantially hollow tubular member
or
members. The drillpipe 2105 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
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goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
material. In a preferred embodiment, the driIlpipe 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, driIling 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 driIling
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 mandrel 2120 is coupled to the sealing sleeve 2115, slips
2125, and the lower sealing head 2135. The inner sealing mandre12120
preferably
comprises a substantially hollow tubular member or members. The inner sealing
mandre12120 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 sealingmandrel 2120 is fabricated from
stainless
steel in order to optimally provide high strength, low friction surfaces, and
corrosion and wear resistance.
The inner sealing mandrel 2120 may be coupled to the sealing sleeve 2115
using any number of conventional commercially available mechanical couplings
such as, for example, drillpipe connection, oilfield country tubular goods
specialty
type threaded connection, or a standard threaded connection. In a preferred
embodiment, the inner sealing mandrel 2120 is removably coupled to the sealing
sleeve 2115 by a standard threaded connection. The standard threaded
connection
provides high strength and permits easy replacement of components. The inner
sealing mandrel 2120 may be coupled to the slips 2125 using any number of
conventional commercially available mechanical couplings such as, for example,
welding, amorphous bonding, or a standard threaded connection. In a preferred
embodiment, the inner sealing mandrel 2120 is removably coupled to the slips
2125 by a standard threaded connection. The inner sealing mandre12120 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 mandrel 2120 is removably coupled to the lower
sealing head 2135 by a standard threaded connection.
The inner sealing mandrel 2120 preferably includes a fluid passage 2175
that is adapted to convey fluidic materials from the fluid passage 2170 into
the
fluid passage 2180. In a preferred embodiment, the fluid passage 2175 is
adapted
to convey fluidic materials such as, for example, cement, epoxy, water,
drillingmud
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 mandrel 2120 and the inner surface of
the
casing 2155. In this manner, the upper sealing head 2130 reciprocates in the
axial
direction. The radial clearance between the inner cylindrical surface of the
upper
sealing head 2130 and the outer surface of the inner sealing mandrel 2120 may
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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, driIlpipe 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 seating head
2130 and the outer sealing mandrel 2140 includes one or more sealing members
2220 for fluidicly seali.ng the interface between the upper sealing head 2130
and
the outer sealing mandrel 2140. The sealing members 2220 may comprise any
number of conventional commercially available sealing members such as, for
example, o-rings, polypak seals, or metal spring energized seals. In a
preferred
embodiment, the sealing members 2220 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
The lower sealing head 2135 is coupled to the inner sealing mandrel 2120
and the load mandrel 2145. The lower sealing head 2135 is also movably coupled
to the inner surface of the outer seali.ng mandrel 2140. In this manner, the
upper
sealing head 2130, outer sealing mandrel 2140, and expansion cone 2150
reciprocate in the axial direction. The radial clearance between the outer
surface
of the lower sealing head 2135 and the inner surface of the outer sealing
mandrel
2140 may range, for example, from about 0.0025 to 0.05 inches. In a preferred
embodiment, the radial clearance between the outer surface of the lower
sealing
head 2135 and the inner surface of the outer sealing mandrel 2140 ranges from
about 0.0025 to 0.05 inches in order to optimally provide minimal radial
clearance.
The lower sealing head 2135 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The lower sealing
head
2135 may be fabricated from any number of conventional conunercially available
materials such as, for example, oilfield country tubular goods, low alloy
steel,
carbon steel, stainless steel or other similar high strength materials. In a
preferred
embodiment, the lower sealing head 2135 is fabricated from stainless steel in
order
to optimally provide high strength, corrosion resistance, and low friction
surfaces.
The outer surface of the lower sealing head 2135 preferably includes one or
more
annular sealing members 2225 for sealing the interface between the lower
sealing
head 2135 and the outer sealing mandrel 2140. The sealing members 2225 may
comprise any number of conventional commercially available annular sealing
members such as, for example, o-rings, polypak seals or metal spring energized
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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, drilipipe connection, oilf'ield 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 seali.ng mandrel 2120 by a standard threaded
connection. In a preferred embodiment, the mechanical coupling between the
lower sealing head 2135 and the inner sealing mandrel 2120 includes one or
more
sealing members 2230 for fluidicly sealing the interface between the lower
sealing
head 2135 and the inner sealing mandrel 2120. The sealing members 2230 may
comprise any number of conventional commercially available sealing members
such as, for example, o-rings, polypak seals, or metal spring energized seals.
In a
preferred embodiment, the sealingmembers 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, drillpipe connection, oilfield country tubular goods specialty
threaded
connection, welding, amorphous bonding, or a standard threaded connection. In
a preferred embodiment, the lower sealing head 2135 is removably coupled to
the
load mandrel 2145 by a standard threaded connection. In a preferred
embodiment, the mechanical coupling between the lower sealing head 2135 and
the load mandrel 2145 includes one or more sealing members 2235 for fluidicly
sealing the interface between the lower sealing head 1930 and the load mandrel
2145. The sealing members 2235 may comprise any number of conventional
commercially available sealing members such as, for example, o-rings, polypak
seals, or metal spring energized seals. In a preferred embodiment, the sealing
members 2235 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for a long axial stroke.
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In a preferred embodiment, the lower sealing head 2135 includes a throat
passage 2240 fluidicly coupled between the fluid passages 2175 and 2180. The
throat passage 2240 is preferably of reduced size and is adapted to receive
and
engage with a plug 2245, or other similar device. In this manner, the fluid
passage
2175 is fluidicly isolated from the fluid passage 2180. In this manner, the
pressure
chamber 2250 is pressurized.
The outer sealing mandre12140 is coupled to the upper sealing head 2130
and the expansion cone 2150. The outer seali.ng mandrel 2140 is also movably
coupled to the inner surface of the casing 2155 and the outer surface of the
lower
seali.ng 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 seali.ng mandre12140
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 mandre12140 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 seali.ng 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 mandre12140 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 seali.ng mandre12140 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The outer sealing
mandre12140 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 sealingmandre12140 is fabricated from
stainless
steel in order to optimally provide high strength, corrosion resistance, and
low
friction surfaces.
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The outer sealing mandrel 2140 may be coupled to the upper sealing head
2130 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods
specialty threaded connection, welding, amorphous bonding or a standard
threaded
connection. In a preferred embodiment, the outer sealing mandrel 2140 is
removably coupled to the upper sealing head 2130 by a standard threaded
connection. The outer sealing mandrel 2140 may be coupled to the expansion
cone
2150 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods
specialty threaded connection, welding, amorphous bonding, or a standard
threaded connection. In a preferred embodiment, the outer sealing mandrel 2140
is removably coupled to the expansion cone 2150 by a standard threaded
connection.
The upper sealing head 2130, the lower sealing head 2135, inner sealing
mandrel 2120, and the outer sealing mandrel 2140 together define a pressure
chamber 2250. The pressure chamber 2250 is fluidicly coupled to the passage
2175
via one or more passages 2255. During operation of the apparatus 2100, the
plug
2245 engages with the throat passage 2240 to fluidicly isolate the fluid
passage
2175 from the fluid passage 2180. The pressure chamber 2250 is then
pressurized
which in turn causes the upper sealing head 2130, outer sealing mandrel 2140,
and
expansion cone 2150 to reciprocate in the axial direction. The axial motion of
the
expansion cone 2150 in turn expands the casing 2155 in the radial direction.
The load mandrel 2145 is coupled to the lower sealing head 2135. The load
mandrel 2145 preferably comprises an annular member having substantially
cylindrical inner and outer surfaces. The load mandrel 2145 may be fabricated
from any number of conventional commercially available materials such as, for
example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel
or other similar high strength materials. In a preferred embodiment, the load
mandrel 2145 is fabricated from stainless steel in order to optimally provide
high
strength, corrosion resistance, and low friction bearing surfaces.
The load mandre12145 may be coupled to the lower sealing head 2135 using
any number of conventional couunercially 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 mandrel 2145 is removably coupled to the
lower
sealing head 2135 by a standard threaded connection in order to optimally
provide
high strength and permit easy replacement of the load mandrel 2145.
The load mandrel 2145 preferably includes a fluid passage 2180 that is
adapted to convey fluidic materials from the fluid passage 2180 to the region
outside of the apparatus 2100. In a preferred embodiment, the fluid passage
2180
is adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud, or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The expansion cone 2150 is coupled to the outer sealing 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 mandrel 2140,
and the expansion cone 2150 reciprocate in the axial direction. The
reciprocation
of the expansion cone 2150 causes the casing 2155 to expand in the radial
direction.
The expansion cone 2150 preferably comprises an annular member having
substantially cylindrical inner and conical outer surfaces. The outside radius
of
the outside conical.surface may range, for example, from about 2 to 34 inches.
In
a preferred embodiment, the outside radius of the outside conical surface
ranges
from about 3 to 28 inches in order to optimally provide cone dimensions that
are
optimal for typical casings. The axial length of the expansion cone 2150 may
range, for example, from about 2 to 6 times the largest outside diameter of
the
expansion cone 2150. In a preferred embodiment, the axial length of the
expansion
cone 2150 ranges from about 3 to 5 times the largest outside diameter of the
expansion cone 2150 in order to optimally provide stability and centralization
of
the expansion cone 2150 during the expansion process. In a particularly
preferred
embodiment, the maximum 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 mandre12140 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 embodirnent, 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 expans:on of the thin walled section
2265
of casing 2155 into the thin walled section of the existing wellbore casing
results
in a wellbore casing having a substantially constant inside diameter.
The annular sealing member 2270 may be fabricated from any number of
conventional commercially available sealing materials such as, for example,
epoxy,
rubber, metal or plastic. In a preferred embodiment, the annular sealing
member
2270 is fabricated from StrataLock epoxy in order to optimally provide
compressibility and resistance to wear. The outside diameter of the annular
sealing member 2270 preferably ranges from about 70 to 95 % of the inside
diameter of the lower section of the wellbore casing that the casing 2155 is
joined
to. In this manner, after expansion, the annular sealing member 2270
preferably
provides a fluidic seal and also preferably provides sufficient frictional
force with
the inside surface of the existing section of wellbore casing during the
radial
expansion of the casing 2155 to support the casing 2155.
In a preferred embodiment, the lower end 2275 of the casing 2155 includes
a thin wall section 2280 and an outer annular sealing member 2285. In a
preferred
embodiment, the wall thickness of the thin wall section 2280 is about 50 to
100 %
of the regular wall thickness of the casing 2155. In this manner, the lower
end
2275 of the casing 2155 may be easily expanded and deformed. Furthermore, in
this manner, an other section of casing may be easily joined with the lower
end
2275 of the casing 2155 using a radial expansion process. In a preferred
embodiment, the upper end of the other section of casing also includes a thin
wall
section. In this manner, the radial expansion of the thin waIled 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
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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 wellbore
with the upper end 2260 of the casing 2155 positioned in an overlapping
relationship with the lower end of an existing wellbore casing. In a
particularly
preferred embodiment, the thin wall section 2265 of the casing 2155 is
positioned
in opposing overlapping relation with the thin wall section and outer annular
sealing member of the lower end of the existing section of welibore casing. In
this
manner, the radial expansion of the casing 2155 wiIl compress the thin wall
sections and annular compressible members of the upper end 2260 of the casing
2155 and the lower end of the existing wellbore casing into intimate contact.
During the positioning of the apparatus 2100 in the wellbore, the casing 2155
is
supported by the expansion cone 2150.
After positioning of the apparatus 2100, a first fluidic material is then
pumped into the fluid passage 2160. The first fluidic material may comprise
any
number of conventional commercially available materials such as, for example,
drilling mud, water, epoxy, or cement. In a preferred embodiment, the first
fluidic
material comprises a hardenable fluidic sealing material such as, for example,
cement or epoxy in order to provide a hardenable outer annular body around the
expanded casing 2155.
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 mandrel 2140 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 mandrel 2140, and expansion cone 2150.
Upon the completion of a stroke, the operating pressure of the second fluidic
material is reduced and the upper sealing head 2130, outer sealing
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 fmal 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 sealingmember 2285 is selected to provide an
interference
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fit with the inside walls of the wellbore at an earlier point in the radial
expansion
process so as to prevent further axial displacement of the casing 2155. In
this
final alternative, the interference fit is preferably selected to permit
expansion of
the casing 2155 by pulling the expansion cone 2150 out of the wellbore,
without
having to pressurize the pressure chamber 2250.
During the radial expansion process, the pressurized areas of the apparatus
2100 are limited to the fluid passages 2160, 2165, 2170, and 2175, the
pressure
chambers 2195 within the slips 2125, and the pressure chamber 2250. No fluid
pressure acts directly on the casing 2155. This permits the use of operating
pressures higher than the casing 2155 could normally withstand.
Once the casing 2155 has been completely expanded off of the expansion
cone 2150, remaining portions of the apparatus 2100 are removed from the
wellbore. In a preferred embodiment, the contact pressure between the deformed
thin wall sections and compressible annular members of the lower end of the
existing casing and the upper end 2260 of the casing 2155 ranges from about
500
to 40,000 psi in order to optimally support the casing 2155 using the existing
wellbore casing.
In this manner, the casing 2155 is radially expanded into contact with an
existing section of casing by pressurizing the interior fluid passages 2160,
2165,
2170, and 2175 and the pressure chamber 2250 of the apparatus 2100.
In a preferred embodiment, as required, the annular body of hardenable
fluidic material is then allowed to cure to form a rigid outer annular body
about
the expanded casing 2155. In the case where the casing 2155 is slotted, the
cured
fluidic material preferably permeates and envelops the expanded casing 2155.
The
resulting new section of wellbore casing includes the expanded casing 2155 and
the
rigid outer annular body. The overlapping joint between the pre-existing
wellbore
casing and the expanded casing 2155 includes the deformed thin wall sections
and
the compressible outer annular bodies. The inner diameter of the resulting
combined wellbore casings is substantially constant. In this manner, a mono-
diameter wellbore casing is formed. This process of expanding overlapping
tubular
members having thin wall end portions with compressible annular bodies into
contact can be repeated for the entire length of a wellbore. In this manner, a
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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
fi equency 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 ahardenable 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 driIlpipe 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 driIlpipe 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 driIlpipe 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 inneratring 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, drillpipe connection, oilfield country tubular goods specialty
threaded
connection, or a standard threaded connection. In a preferred embodiment, the
innerstring adapter 2310 is removably coupled to the drill pipe 2305 by a
drillpipe
connection. The innerstring adapter 2310 may be coupled to the sealing sleeve
2315 using any number of conventional commercially available mechanical
couplings such as, for example, a drillpipe connection, oilfield country
tubular
goods specialty threaded connection, or a standard threaded connection. In a
preferred embodiment, the innerstring adapter 2310 is removably coupled to the
sealing sleeve 2315 by a standard threaded connection.
The innerstring adapter 2310 preferably includes a fluid passage 2385 that
is adapted to convey fluidic materials from the fluid passage 2380 into the
fluid
passage 2390. In a preferred embodiment, the fluid passage 2385 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud,
driIling 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
hydxaulic 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
mandrei 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 seali.ng 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,
iirilling 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 seali.ng head 2340. The inner sealing mandrel 2330 preferably
comprises a substantially hollow tubular member or members. The inner sealing
mandre12330 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy
steel, carbon steel, stainless steel or other similar high strength materials.
In a
preferred embodiment, the inner sealing mandrel 2330 is fabricated from
stainless
steel in order to optimally provide high strength, corrosion resistance, and
low
friction surfaces.
The inner sealing mandre12330 u~.ay 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 mandrel 2330
is removably coupled to the lower sealing head 2340 by a standard threaded
connection.
The inner seali.ng 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 seali.ng 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 mandrel 2330. The sealing members 2435 may
comprise any number of conventional commercially available annular sealing
members such as, for example, o-rings, polypak seals or metal spring energized
seals. In a preferred enzbodi.ment, 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 sealing head 2335 includes a shoulder
2440 for supporting the upper sealing head on the lower sealing head 1930.
The upper sealing head 2335 may be coupled to the outer sealing mandrel
2350 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods
specialty threaded connection, welding, amorphous bonding, or a standard
threaded connection. In a preferred embodiment, the upper sealing head 2335 is
removably coupled to the outer sealing mandrel 2350 by a standard threaded
connection. In a preferred embodiment, the mechanical coupling between the
upper sealing head 2335 and the outer sealing mandrel 2350 includes one or
more
sealing members 2445 for fluidicly sealing the interface between the upper
sealing
head 2335 and the outer sealing mandrel 2350. The sealing members 2445 may
comprise any number of conventional commercially available seali.ng members
such as, for example, o-rings, polypak seals or metal spring energized seals.
In a
preferred embodiment, the sealing members 2445 comprise polypak seals
available
from Parker Seals in order to optimally provide sealing for long axial
strokes.
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, corrosion resistance, and low friction
surfaces.
The outer surface of the lower sealing head 2340 preferably includes one or
more
annular sealing members 2450 for sealing the interface between the lower
sealing
head 2340 and the outer sealing mandrel 2350. The sealing members 2450 may
comprise any number of conventional commercially available annular sealing
members such as, for example, o-rings, polypak seals or metal spring energized
seals. In a preferred embodiment, the sealing members 2450 comprise polypak
seals available from Parker Seals in order to optimally provide sealing for a
long
axial stroke.
The lower sealing head 2340 may be coupled to the inner sealing mandrel
2330 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
specialty threaded connection, welding, amorphous bonding, or standard
threaded
connection. In a preferred embodiment, the lower sealing head 2340 is
removably
coupled to the inner sealing mandre12330 by a standard threaded connection. In
a preferred embodiment, the mechanical coupling between the lower sealing head
2340 and the inner sealing mandrel 2330 includes one or more sealing members
2455 for fluidicly sealing the interface between the lower sealing head 2340
and
the inner sealing mandrel 2330. The sealing members 2455 may comprise any
number of conventional commercially available sealing members such as, for
example, o-rings, polypak or metal spring energized seals. In a preferred
embodiment, the sealing members 2455 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke
length.
The lower sealing head 2340 may be coupled to the load mandrel 2345 using
any number of conventional commercially available mechanical couplings such
as,
for example, drillpipe connection, oilfield country tubular goods specialty
threaded
connection, welding, amorphous bonding or a standard threaded connection. In
a preferred embodiment, the lower sealing head 2340 is removably coupled to
the
load mandrel 2345 by a standard threaded connection. In a preferred
embodiment, the mechanical coupling between the lower sealing head 2340 and
the load mandre12345 includes one or more sealing members 2460 for fluidicly
sealing the interface between the lower sealing head 2340 and the load mandrel
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2345. The sealing members 2460 may comprise any number of conventional
commercially available sealing members such as, for example, o-rings, polypak
seals or metal spring energized seals. In a preferred embodiment, the sealing
members 2460 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for a long axial stroke length.
In a preferred embodiment, the lower sealing head 2340 includes a throat
passage 2465 fluidicly coupled between the fluid passages 2405 and 2415. The
throat passage 2465 is preferably of reduced size and is adapted to receive
and
engage with a plug 2470, or other similar device. In this manner, the fluid
passage
2405 is fluidicly isolated from the fluid passage 2415. In this manner, the
pressure
chamber 2475 is pressurized.
The outer seali.ng mandre12350 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 mandre12350
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 mandre12350 and the inner surface of the casing
2375
ranges from about 0.025 to 0.125 inches in order to optimally provide
stabilization
for the expansion cone 2355 during the expansion process. The radial clearance
between the inner surface of the outer sealing mandrel 2350 and the outer
surface
of the lower sealing head 2340 may range, for example, from about 0.0025 to
0.375
inches. In a preferred embodiment, the radial clearance between the inner
surface
of the outer sealing mandrel 2350 and the outer surface of the lower sealing
head
2340 ranges from about 0.005 to 0.010 inches in order to optimally provide
minimal clearance.
The outer sealing mandre12350 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The outer sealing
mandrel 2350 may be fabricated from any number of conventional commercially
available materials such as, for example, low alloy steel, carbon steel,
stainless steel
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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 etrength, corrosion resistance, and low friction surfaces.
The outer seali.ng 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 define a pressure
chamber 2475. The pressure chamber 2475 is fluidicly coupled to the passage
2405
via one or more passages 2410. During operation of the apparatus 2300, the
plug
2470 engages with the throat passage 2465 to fluidicly isolate the fluid
passage
2415 from the fluid passage 2405. The pressure chamber 2475 is then
pressurized
which in turn causes the upper sealing head 2335, outer sealing mandrel 2350,
and
expansion cone 2355 to reciprocate in the axial direction. The axial motion of
the
expansion cone 2355 in turn expands the casing 2375 in the radial direction.
The load mandrel 2345 is coupled to the lower sealing head 2340 and the
mechanical slip body 2360. The load mandrel 2345 preferably comprises an
annular member having substantially cylindrical inner and outer surfaces. The
load mandrel 2345 may be fabricated from any number of conventional
commercially available materials such as, -for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the load mandrel 2345 is fabricated from
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stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces.
The load mandrel 2345 maybe 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
seali.ng 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 mandrel 2350. The.
expansion cone 2355 is also movably coupled to the inner surface of the casing
2375. In this manner, the upper sealing head 2335, outer sealing mandrel 2350,
and the expansion cone 2355 reciprocate in the axial direction. The
reciprocation
of the expansion cone 2355 causes the casing 2375 to expand in the radial
direction.
The expansion cone 2355 preferably comprises an annular member having
substantially cylindrical inner and conical outer surfaces. The outside radius
of
the outside conical surface may range, for example, from about 2 to 34 inches.
In
a preferred embodiment, the outside radius of the outside conical surface
ranges
from about 3 to 28 inches in order to optimally provide radial expansion of
the
typical casings. The axial length of the expansion cone 2355 may range, for
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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 mandrel 2350 using a standard threaded
connection
in order to optimally provide high strength and permit the expansion cone 2355
to be easily replaced.
The mandrel launcher 2480 is coupled to the casing 2375. The mandrel
launcher 2480 comprises a tubular section of casing having a reduced wall
thickness compared to the casing 2375. In a preferred embodiment, the wall
thickness of the mandrel launcher 2480 is about 50 to 100 % of the wall
thickness
of the casing 2375. In this manner, the initiation of the radial expansion of
the
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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 optim.ally 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
mandrel 2345 using threads and sliding steel retaining rings in order to
optimally
provide a high strength attachment. The mechanical slip body 2360 may be
coupled to the mechanical slips 2365 using any number of conventional
mechanical
couplings. In a preferred embodiment, the mechanical slip body 2360 is
removably
coupled to the mechanical slips 2365 using threads and sliding steel retaining
rings
in order to optimally provide a high strength attachment. The mechanical slip
body 2360 may be coupled to the drag blocks 2370 usiiig any number of
conventional mechanical couplings. In a preferred enibodi.ment, 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 optimally provide a high strength
attachment.
The mechanical slips 2365 are coupled to the outside surface of the
mechanical slip body 2360. During operation of the apparatus 2300, the
mechanical slips 2365 prevent upward movement of the casing 2375 and mandrel
launcher 2480. In this manner, during the axial reciprocation of the expansion
cone 2355, the casing 2375 and mandrel launcher 2480 are maintained in a
substantially stationary position. In this manner, the mandrel launcher 2480
and
casing 2375 are expanded in the radial direction by the axial movement of the
expansion cone 2355.
The mechanical slips 2365 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer
tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or
Model 3L retrievable bridge plug tungsten carbide upper mechanical slips. In a
preferred embodiment, the mechanical slips 2365 comprise RTTS packer tungsten
carbide mechanicai slips available from Halliburton Energy Services in order
to
optimally provide resistance to axial movement of the casing 2375 during the
expansion process.
The drag blocks 2370 are coupled to the outside surface of the mechanical
slip body 2360. During operation of the apparatus 2300, the drag blocks 2370
prevent upward movement of the casing 2375 and mandrel launcher 2480. In this
manner, during the axial reciprocation of the expansion cone 2355, the casing
2375
and mandrel launcher 2480 are maintained in a substantially stationary
position.
In this manner, the mandrel launcher 2480 and casing 2375 are expanded in the
radial direction by the axial movement of the expansion cone 2355.
The drag blocks 2370 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer
mechanical drag blocks or Model 3L retrievable bridge plug drag blocks. In a
preferred embodiment, the drag blocks 2370 comprise RTTS packer mechanical
drag blocks available from Halliburton Energy Services in order to optimally
provide resistance to axial movement of the casing 2375 during the expansion
process.
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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, carbon steel,
low alloy
steel, stainless steel or other similar high strength materials. In a
preferred
embodiment, the casing 2375 is fabricated from oilfield country tubular goods
available from various foreign and domestic steel mills in order to optimally
provide high strength. In a preferred embodiment, the upper end of the casing
2375 includes one or more sealing members positioned about the exterior of the
casing 2375.
During operation, the apparatus 2300 is positioned in a wellbore with the
upper end of the casing 2375 positioned in an overlapping relationship within
an
existing wellbore casing. In order minimize surge pressures within the
borehole
during placement of the apparatus 2300, the fluid passage 2380 is preferably
provided with one or more pressure relief passages. During the placement of
the
apparatus 2300 in the wellbore, the casing 2375 is supported by the expansion
cone
2355.
After positioning of the apparatus 2300 within the bore hole in an
overlapping relationship with an existing section of wellbore casing, a first
fluidic
material is pumped into the fluid passage 2380 from a surface location. The
first
fluidic material is conveyed from the fluid passage 2380 to the fluid passages
2385,
2390, 2395, 2405, 2415, and 2485. The first fluidic material will then exit
the
apparatus 2300 and fill the annular region between the outside of the
apparatus
2300 and the interior walLs of the bore hole.
The first fluidic material may comprise any number of conventional
commercially available materials such as, for example, epoxy, drilling mud,
slag
mix, cement, or water. In a preferred embodiment, the first fluidic material
comprises a hardenable fluidic sealing material such as, for example, slag
mix,
epoxy, or cement. In this manner, a wellbore casing having an outer annular
layer
of a hardenable material may be formed.
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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
mandrel 2345, 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 P.xpansion cone 2355 nears the upper end
of the casing 2375, the operating pressure of the second fluidic material is
reduced
in order to minim;ze 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 rad.ially 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, inechanical 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 apphcable, 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 drillpipe connection provides the advantages
of
high strength and easy disassembly.
The drillpipe 2505 preferably includes a fluid passage 2565 that is adapted
to convey fluidic materials from a surface location into the fluid passage
2570. In
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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, driIIpipe 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 embodiment, the sealing sleeve 2515 is
removably coupled to the innerstring adapter 2510 by a standard threaded
connection. The sealing sleeve 2515 may be coupled to the hydraulic slip body
2520 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods.
specialty type threaded connection, ratchet-latch type threaded connection, or
a
standard threaded connection. In a preferred embodiment, the sealing sleeve
2515
is removably coupled to the hydraulic slip body 2520 by a standard threaded
connection.
The sealing sleeve 2515 preferably includes a fluid passage 2575 that is
adapted to convey fluidic materials from the fluid passage 2570 into the fluid
passage 2580. In a preferred embodiment, the fluid passage 2575 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud
or lubricants at operating pressures_ and flow rates ranging from about 0 to
9,000
psi and 0 to 3,000 gallons/minute.
The hydraulic slip body 2520 is coupled to the sealing sleeve 2515, the
hydraulic slips 2525, and the inner sealing mandrel 2530. The hydraulic slip
body
2520 preferably comprises a substantially hollow tubular member or members.
The hydraulic slip body 2520 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
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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 mandrel 2530
using
any number of conventional commercially available mechanical couplings such
as,
for example, drillpipe connection, oilfield country tubular goods specialty
type
threaded connection, welding, amorphous bonding or a standard threaded
connection. In a preferred embodiment, the hydraulic slip body 2520 is
removably
coupled to the inner sealing mandrel 2530 by a standard threaded connection.
The hydraulic slips body 2520 preferably includes a fluid passage 2580 that
is adapted to convey fluidic materials from the fluid passage 2575 into the
fluid
passage 2590. In a preferred embodiment, the fluid passage 2580 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud
or lubricants at operating pressures and flow rates ranging from about 0 to
9,000
psi and 0 to 3,000 gallons/minute.
The hydraulic slips body 2520 preferably includes fluid passages 2585 that
are adapted to convey fluidic materials from the fluid passage 2580 into the
pressure chambers of the hydraulic slips 2525. In this manner, the slips 2525
are
activated upon the pressurization of the fluid passage 2580 into contact with
the
inside surface of the casing 2560. In a preferred embodiment, the fluid
passages
2585 are adapted to convey fluidic materials such as, for example, water,
drilling
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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 hvdraulic 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 mandrel 2530 is fabricated from
stainless
steel in order to optimally provide high strength, corrosion resistance, and
low
friction surfaces.
The inner sealing mandrel 2530 may be coupled to the hydraulic slip body
2520 using any number of conventional commercially available mechanical
coupli.ngs 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 mandre12530
is removably coupled to the hydraulic slip body 2520 by a standard threaded
connection. The inner sealing mandrel 2530 may be coupled to the lower sealing
head 2540 using any number of conventional commercially available mechanical
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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 seali.ng 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 mandre12545
and expansion cone 2555. The upper sealing head 2535 is also movably coupled
to
the outer surface of the inner sealing mandrel 2530 and the inner surface of
the
casing 2560. In this manner, the upper sealing head 2535 reciprocates in the
axial
direction. The radial clearance between the inner cylindrical surface of the
upper
sealing head 2535 and the outer surface of the inner sealing mandrel 2530 may
range, for example, from about 0.0025 to 0.05 inches. In a preferred
embodiment,
the radial clearance between the inner cylindrical surface of the upper
sealing head
2535 and the outer surface of the inner sealing mandrel 2530 ranges from about
0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
The
radial clearance between the outer cylindrical surface of the upper sealing
head
2535 and the inner surface of the casing 2560 may range, for example, from
about
0.025 to 0.375 inches. In a preferred embodiment, the radial clearance between
the outer cylindrical surface of the upper sealing head 2535 and the inner
surface
of the casing 2560 ranges from about 0.025 to 0.125 inches in order to
optimally
provide stabilization for the expansion cone 2535 during the expansion
process.
The upper sealing head 2535 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The upper sealing
head
2535 may be fabricated from any number of conventional commercially available
materials such as, for example, oilfield country tubular goods, ow alloy
steel,
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carbon steel, stainless steel or other similar high strength materials. In a
preferred
embodiment, the upper sealing head 2535 is fabricated from stainless steel in
order
to optimally provide high strength, corrosion resistance, and low friction
surfaces.
The inner surface of the upper sealing head 2535 preferably includes one or
more
annular sealing members 2620 for sealing the interface between the upper
sealing
head 2535 and the inner sealing mandrel 2530. The sealing members 2620 may
comprise any number of conventional commercially available annular sealing
members such as, for example, o-rings, polypak seals, or metal spring
energized
seals. In a preferred embodiment, the seali.ng 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 mandre12545,
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, oilf"ield country tubular goods specialty
threaded
connection, pipeline connection, welding, amorphous bonding, or a standard
threaded connection. In a preferred embodiment, the upper sealing head 2535 is
removably coupled to the outer sealing mandrel 2545 by a standard threaded
connection. In a preferred embodiment, the mechanical coupling between the
upper sealing head 2535 and the outer sealing mandrel 2545 includes one or
more
sealing members 2630 for fluidicly sealing the interface between the upper
sealing
head 2535 and the outer sealing mandrel 2545. The sealing members 2630 may
comprise any number of conventional commeraially 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 mandre12550. The lower sealing head 2540 is also movably coupled
to the inner surface of the outer sealing mandre12545. In this manner, the
upper
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sealing head 2535, outer sealing mandrel 2545, and expansion cone 2555
reciprocate in the axial direction.
The radial clearance between the outer surface of the lower sealing head
2540 and the inner surface of the outer sealing mandrel 2545 may range, for
example, from about 0.0025 to 0.05 'inches. In a preferred embodiment, the
radial
clearance between the outer surface of the lower sealing head 2540 and the
inner
surface of the outer sealing mandre1.2545 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
seali.ng
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 seali.ng 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
mandre12530 includes one or more sealing members 2640 for fluidicly sealing
the
interface between the lower sealing head 2540 and the inner sealing mandrel
2530.
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The sealing members 2640 may comprise any number of conventional
commercially available sealing members such as, for example, o-rings, polypak
seals or metal spring energized seals. In a preferred embodiment, the sealing
members 2640 comprise polypak seals available from Parker Seals in order to
optimafly 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 mandrel 2550 includes one or more sealing members 2645 for
fluidicly sealing the interface between the lower sealing head 2540 and the
load
mandrel 2550. The sealing members 2645 may comprise any number of
conventional commercially available sealing members such as, for example, o-
rings,
polypak seals or metal spring energized seals. In a preferred emboditnent, the
sealing members 2645 comprise polypak seals available from Parker Seals in
order
to optimally provide sealing for a long axial stroke.
In a preferred embodiment, the lower sealing head 2540 includes a throat
passage 2650 fluidicly coupled between the fluid passages 2590 and 2600. The
throat passage 2650 is preferably of reduced size and is adapted to receive
and
engage with a plug 2655, or other similar device. In this manner, the fluid
passage
2590 is fluidicly isolated from the fluid passage 2600. In this manner, the
pressure
chamber 2660 is pressurized.
The outer sealing mandrel 2545 is coupled to the upper sealing head 2535
and the expansion cone 2555. The outer sealing mandrel 2545 is also movably
coupled to the inner surface of the casing 2560 and the outer surface of the
lower
sealing head 2540. In this manner, the upper sealing head 2535, outer sealing
mandrel 2545, and the expansion cone 2555 reciprocate in the axial direction.
The
radial clearance between the outer surface of the outer sealing mandre12545
and
the inner surface of the casing 2560 may range, for example, from about 0.025
to
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0.375 inches. In a preferred embodiment, the radial clearance between the
outer
surface of the outer sealing mandrel 2545 and the inner surface of the casing
2560
ranges from about 0.025 to 0.125 inches in order to optimally provide
stabilization
for the expansion cone 2535 during the expansion process. The radial clearance
between the inner surface of the outer sealing mandrel 2545 and the outer
surface
of the lower sealing head 2540 may range, for example, from about 0.005 to
0.01
inches. In a preferred embodiment, the radial clearance between the inner
surface
of the outer sealing mandrel 2545 and the outer surface of the lower sealing
head
2540 ranges from about 0.005 to 0.01 inches in order to optimally provide
minimal
radial clearance.
The outer sealing mandrel 2545 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The outer sealing
mandrel 2545 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy
steel, carbon steel, stainless steel or other similar high strength materials.
In a
preferred embodiment, the outer sealing 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 mandrel 2545
is removably coupled to the upper sealing head 2535 by a standard threaded
connection. The outer sealing mandrel 2545 may be coupled to the expansion
cone
2555 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods
specialty type threaded connection, welding, amorphous bonding, or a standard
threaded connection. In a preferred embodiment, the outer sealing mandrel 2545
is removably coupled to the expansion cone 2555 by a standard threaded
connection.
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The upper sealing head 2535, the lower sealing head 2540, the inner sealing
mandrel 2530, and the outer seali.ng mandrel 2545 together define a pressure
chamber 2660. The pressure chamber 2660 is fluidicly coupled to the passage
2590
via one or more passages 2595. During operation of the apparatus 2500, the
plug
2655 engages with the throat passage 2650 to fluidicly isolate the fluid
passage
2590 from the fluid passage 2600. The pressure chamber 2660 is then
pressurized
which in turn causes the upper sealing head 2535, outer sealing mandrel 2545,
and
expansion cone 2555 to reciprocate in the axial direction_ The axial motion of
the
expansion cone 2555 in turn expands the casing 2560 in the radial direction.
The load mandrel 2550 is coupled to the lower sealing head 2540. The load
mandrel 2550 preferably comprises an annular member having substantially
cylindrical inner and outer surfaces. The load mandrel 2550 may be fabricated
from any number of conventional commercially available materials such as, for
example, oilfield country tubular goods, low alloy steel, carbon steel,
stainless steel
or other similar high strength materials. In a preferred embodiment, the load
mandrel 2550 is fabricated from stainless steel in order to optimally provide
high
strength, corrosion resistance, and low friction surfaces.
The load mandrel 2550 may be coupled to the lower sealing head 2540 using
any number of conventional commercially available mechanical couplings such
as,
for example, oilfield country tubular goods, drillpipe connection, welding,
amorphous bonding, or a standard threaded connection. In a preferred
embodiment, the load mandrel 2550 is removably coupled to the lower sealing
head
2540 by a standard threaded connection.
The load mandrel 2550 preferably includes a fluid passage 2600 that is
adapted to convey fluidic materials from the fluid passage 2590 to the region
outside of the apparatus 2500. In a preferred embodiment, the fluid passage
2600
is adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud, or lubricants at operating pressures and flow rates ranging, for
example, from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The expansion cone 2555 is coupled to the outer sealing mandrel 2545. The
expansion cone 2555 is also movably coupled to the inner surface of the casing
2560. In this manner, the upper sealing head 2535, outer sealing mandrel 2545,
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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.
The expansion cone 2555 preferably comprises an annular member having
substantially cylindrical inner and conical outer surfaces. The outside radius
of
the outside conical surface may range, for example, from about 2 to 34 inches.
In
a preferred embodiment, the outside radius of the outside conical surface
ranges
from about 3 to 28 in order to optimally provide radial expansion for the
widest
variety of tubular casings. The axial length of the expansion cone 2555 may
range,
for example, from about 2 to 8 times the largest outside diameter of the
expansion
cone 2535. In a preferred embodiment, the axial length of the expansion cone
2535
ranges from about 3 to 5 times the largest outside diameter of the expansion
cone
2535 in order to optimally provide stabilization and centralization of the
expansion
cone 2535 during the expansion process. In a particularly preferred
embodiment,
the maximum outside diameter of the expansion cone 2555 is between about 95 to
99 % of the inside diameter of the existing wellbore that the casing 2560 will
be
joined with. In a preferred embodiment, the angle of attack of the expansion
cone
2555 ranges from about 5 to 30 degrees in order to optimally balance
frictional
forces and radial expansion forces. The optimum angle of attack of the
expansion
cone 2535 will vary as a function of the particular operational features of
the
expansion operation.
The expansion cone 2555 may be fabricated from any number of
conventional commercially available materials such as, for example, machine
tool
steel, nitride steel, titanium, tungsten carbide, ceramics or other similar
high
strength materials. In a preferred embodiment, the expansion cone 2555 is
fabricated from D2 machine tool steel in order to optimally provide high
strength,
and resistance to wear and galling. In a particularly preferred embodiment,
the
outside surface of the expansion cone 2555 has a surface hardness ranging from
about 58 to 62 Rockwell C in order to optimally provide high strength and wear
resistance.
The expansion cone 2555 may be coupled to the outside sealing mandrel
2545 using any number of conventional commercially available mechanical
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couplings such as, for example, drillpipe connection, oi]field country tubular
goods
specialty threaded connection, welding, amorphous bonding or a standard
threaded
connection. In a preferred embodiment, the expansion cone 2555 is coupled to
the
outside sealing mandrel 2545 using a standard threaded connection in order to
optimally provide high strength and easy replacement of the expansion cone
2555.
The casing 2560 is removably coupled to the slips 2525 and expansion cone
2555. The casing 2560 preferably comprises. a tubular member. The casing 2560
may be fabricated from any number of conventional commercially available
materials such as, for example, slotted tubulars, oilfield country tubular
goods, low
alloy steel, carbon steel, stainless steel or other similar high strength
materials.
In a preferred embodiment, the casing 2560 is fabricated from oilfield country
tubular goods available from various foreign and domestic steel mills in order
to
optimally provide high strength using standardized materials.
In a preferred embodiment, the upper end 2665 of the casing 2560 includes
a thin wall section 2670 and an outer annular sealing member 2675. In a
preferred
embodiment, the wall thickness of the thin wall section 2670 is about 50 to
100 %
of the regular wall thickness of the casing 2560. In this manner, the upper
end
2665 of the casing 2560 may be easily radially expanded and deformed into
intimate contact with the lower end of an existing section of wellbore casing.
In
a preferred embodiment, the lower end of the existing section of casing also
includes a thin wall section. In this manner, the radial expansion of the
thin.
walled section 2670 of casing 2560 into the thin walled section of the
existing
wellbore casing results in a wellbore casing having a substantially constant
inside
diameter.
The annular sealing member 2675 may be fabricated from any number of
conventional commercially available sealing materials such as, for example,
epoxy,
rubber, metal, or plastic. In a preferred embodiment, the annular sealing
member
2675 is fabricated from StrataLock epoxy in order to optimally provide
compressibility and resistance to wear. The outside diameter of the annular
sealing member 2675 preferably ranges from about 70 to 95 % of the 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
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optimally provides a fluidic seal and also preferably optimally provides
sufficient
frictional force with the inside surface of the existing section of wellbore
casing
during the radial expansion of the casing 2560 to support the casing 2560.
In a preferred embodiment, the lower end 2680 of the casing 2560 includes
a thin wall section 2685 and an outer annular sealing member 2690. In a
preferred
embodiment, the wall thickness of the thin wall section 2685 is about 50 to
100 %
of the regular wall thickness of the casing 2560. In this manner, the lower
end
2680 of the casing 2560 may be easily expanded and deformed. Furthermore, in
this manner, an other section of casing may be easily joined with the lower
end
2680 of the casing 2560 using a radial expansion process. In a preferred
embodiment, the upper end of the other section of casing also includes a thin
wall
section. In this manner, the radial expansion of the thin walled section of
the
upper end of the other casing into the thin walled section 2685 of the lower
end
2680 of the casing 2560 results in a wellbore casing having a substantially
constant
inside diameter.
The annular sealing member 2690 may be fabricated from any number of
conventional commercially available sealing materials such as, for example,
rubber,
metal, plastic or epoxy. In a preferred embodiment, the annular sealing member
2690 is fabricated from StrataLock epoxy in order to optimally provide
compressibility and resistance to .wear. The outside diameter of the annular
sealing member 2690 preferably ranges from about 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 wellbore casing. In
this
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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 weIlbore casing into intimate contact.
During the positioning of the apparatus 2500 in the wellbore, the casing 2560
is
supported by the expansion cone 2555.
After positioning of the apparatus 2500, a first fluidic material is then
pumped into the fluid passage 2565. The first fluidic material may comprise
any
number of conventional commercially available materials such as, for example,
cement, water, slag-mix, epoxy or drilling mud. In a preferred embodiment, the
first fluidic material comprises a hardenable fluidic seali.ng 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/m.i.nute 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 ofvotumes 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-
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hardenable fluidic material such as, for example, water, drilling mud, or
lubricant
in order to optimally provide pressurization of the pressure chamber 2660 and
minimi~e friction.
The second fluidic material may be pumped into the fluid passage 2565 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi
and 0 to 4,500 gallons/minute. In a preferred embodiment, the second fluidic
material is pumped into the fluid passage 2565 at operating pressures and flow
rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order
to
optimally provide operational efficiency.
The second fluidic material pumped into the fluid passage 2565 passes
through the fluid passages 2570, 2575, 2580, 2590 and into the pressure
chambers
2605 of the slips 2525, and into the pressure chamber 2660. Continued pumping
of the second fluidic material pressurizes the pressure chambers 2605 and
2660.
The pressurization of the pressure chambers 2605 causes the slip members
2525 to expand in the radial direction and grip the interior surface of the
casing
2560. The casing 2560 is then preferably maintained in a substantially
stationary
position.
The pressurization of the pressure chamber 2660 causes the upper sealing
head 2535, outer sealing mandrel 2545 and expansion cone 2555 to move in an
axial direction relative to the casing 2560. In this manner, the expansion
cone
2555 will cause the casing 2560 to expand in the radial direction, beginning
with
the lower end 2685 of the casing 2560.
During the radial expansion process, the casing 2560 is prevented from
moving in an upward direction by the slips 2525. A length of the casing 2560
is
then expanded in the radial direction through the pressurization of the
pressure
chamber 2660. The length of the casing 2560 that is expanded during the
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 driIlpipe 2505 is
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preferably adjusted throughout the radial expansion process in order to
maintain
the overlapping relationship between the thin walled sections of the lower end
of
the existing wellbore casing and the upper end of the casing 2560. In a
preferred
embodiment, the stroking of the expansion cone 2555 is then repeated, as
necessary, until the thin walled section 2670 of the upper end 2665 of the
casing
2560 is expanded into the thin walled section of the lower end of the existing
wellbore casing. In this manner, a wellbore casing is formed including two
adjacent sections of casing having a substantially constant inside diameter.
This
process may then be repeated for the entirety of the wellbore to provide a
wellbore
casing thousands of feet in length having a substantially constant inside
diameter.
In a preferred embodiment, during the fmal stroke of the expansion cone
2555, the slips 2525 are positioned as close as possible to the thin walled
section
2670 of the upper end 2665 of the casing 2560 in order minimize slippage
between
the casing 2560 and the existing wellbore casing at the end of the radial
expansion
process. Alternatively, or in addition, the outside diameter of the annular
sealing
member 2675 is selected to ensure sufficient interference fit with the inside
diameter of the lower end of the existing casing to prevent axial displacement
of
the casing 2560 during the final stroke. Alternatively, or in addition, the
outside
diameter of the annular sealing member 2690 is selected to provide an
interference
fit with the inside walls of the wellbore at an earlier point in the radial
expansion
process so as to prevent further axial displacement of the casing 2560. In
this
fmal 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
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wellbore. In a preferred embodiment, the contact pressure between the deformed
thin wall sections and compressible annular members of the lower end of the
existing casing and the upper end 2665 of the casing 2560 ranges from about
400
to 10,000 psi in order to optimally support the casing 2560 using the existing
wellbore casing.
In this manner, the casing 2560 is radially expanded into contact with an
existing section of casing by pressurizing the interior fluid passages 2565,
2570,
2575, 2580, and 2590, the pressure chambers of the slips 2605 and the pressure
chamber 2660 of the apparatus 2500.
In a preferred embodiment, as required, the annular body of hardenable
fluidic material is then allowed to cure to form a rigid outer annular body
about
the expanded casing 2560. In the case where the casing 2560 is slotted, the
cured
fluidic material preferably permeates and envelops the expanded casing 2560.
The
resulting new section ofwellbore casing includes the expanded casing 2560 and
the
rigid outer annular body. The overlapping joint between the pre-existing
wellbore
casing and the expanded casing 2560 includes the deformed thin wall sections
and
the compressible outer annular bodies. The inner diameter of the resulting
combined wellbore casings is substantially constant. In this manner, a mono-
diameter wellbore casing is formed. This process of expanding overlapping
tubular
members having thin wall end portions with compressible annular bodies into
contact can be repeated for the entire length of a wellbore. In this manner, a
mono-diameter wellbore casing can be provided for thousands of feet in a
subterranean formation.
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,
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the operating pressure of the second fluidic material is reduced during the
return
stroke of the apparatus 2500 to the range of about 0 to 500 psi in order
minimize
the resistance to the movement of the expansion cone 2555 during the return
stroke. In apreferred embodiment, the stroke length of the apparatus 2500
ranges
from about 10 to 45 feet in order to optiunally 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 ahardenable 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 flrst inner sealing mandre12720, a first upper sealing head
2725, a
first lower sealing head 2730, a first outer sealing mandrel 2735, a second
inner
sealing mandre12740, 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 substantiatly 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
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goods, Iow alloy steel, carbon steel, stainless steel, or other similar high
strength
materials. In a preferred embodiment, the drillpipe 2705 is fabricated from
coiled
tubing in order to facilitate the placement of the apparatus 2700 in non-
vertical
wellbores. The drillpipe 2705 may be coupled to the innerstring adapter 2710
using any number of conventional commercially available mechanical couplings
such as, for example, driIlpipe connection, oilfield country tubular goods
specialty
threaded connection, or a standard threaded connection. In a preferred
embodiment, the drilipipe 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 liigh strength materials. In a
preferred
embodiment, the innerstring adapter 2710 is fabricated from stainless steel in
order to optimally provide high strength, corrosion resistance, and low
friction
surfaces. -
The innerstring adapter 2710 may be coupled to the drill string 2705 using
any number of conventional commercially available mechanical couplings such
as,
for example, drillpipe connection, oilfield country tubular goods specialty
threaded
connection, or a standard threaded connection. In a preferred embodiment, the
innerstring adapter 2710 is removably coupled to the drill pipe 2705 by a
standard
threaded connection in order to optimally provide high strength and easy
disassembly. The innerstring adapter 2710 may be coupled to the sealing sleeve
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2715 using any number of conventional commercially available mechanical
couplings such as, for example, driIlpipe connection, oilfield country tubular
goods
specialty type threaded connection, ratchet-latch type threaded connection or
a
standard threaded connection. In a preferred embodiment, the innerstring
adapter
2710 is removably coupled to the sealing sleeve 2715 by a standard threaded
connection.
The innerstring adapter 2710 preferably includes a fluid passage 2800 that
is adapted to convey fluidic materials from the fluid passage 2795 into the
fluid
passage 2805. In a preferred embodiment, the fluid passage 2800 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud
or lubricants at operating pressures and flow rates ranging from about 0 to
9,000
psi and 0 to 3,000 gallons/minute.
The sealing sleeve 2715 is coupled to the innerstring adapter 2710 and the
first inner sealing mandrel 2720. The sealing sleeve 2715 preferably comprises
a
substantially hollow tubular member or members. The sealing sleeve 2715 may
be fabricated from any number of conventional commercially available materials
such as, for example, oilfield country tubular goods, low alloy steel, carbon
steel,
stainless steel or other similar high strength materials. In a preferred
embodiment, the sealing sleeve 2715 is fabricated from stainless steel in
order to
optimally provide high strength, corrosion resistance, and low friction
surfaces.
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, oilffeld 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.
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The sealing sleeve 2715 preferably includes a fluid passage 2802 that is
adapted to convey fluidic materials from the fluid passage 2800 into the fluid
passage 2805. In a preferred embodiment, the fluid passage 2802 is adapted to
convey fluidic materials such as, for example, cement, epoxy, water, drilling
mud
or lubricants at operating pressures and flow rates ranging from about 0 to
9,000
psi and 0 to 3,000 gallons/minute.
The first inner sealing mandrel 2720 is coupled to the sealing sleeve 2715
and the first lower sealing head 2730. The first inner sealing mandrel 2720
preferably comprises a substantially hollow tubular member or members. The
first
inner sealing mandrel 2720 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the first inner sealing mandrel 2720 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The first inner sealing mandrel 2720 may be coupled to the sealing sleeve
2715 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection oilfield country tubular
goods
specialty threaded connection, welding, amorphous bonding, or a 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 maybe coupled to the first
lower
sealing head 2730 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, welding, amorphous bonding,
or a standard threaded connection. In a preferred embodiment, the first inner
sealing mandrel 2720 is removably coupled to the first lower sealing head 2730
by
a standard threaded connection.
The first inner sealing mandrel 2720 preferably includes a fluid passage
2805 that is adapted to convey fluidic materials from the fluid passage. 2802
into
the fluid passage 2810. In a preferred embodiment, the fluid passage 2805 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
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drilling mud or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The 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 seali.ng 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 mandre12720 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 member
having substantially cylindrical inner and outer surfaces. The first upper
sealing
head 2725 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy
steel, carbon steel, stainless steel or other similar high strength materials.
In a
preferred embodiment, the first upper sealing head 2725 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance and
low friction surfaces. The inner surface of the first upper sealing head 2725
preferably includes one or more annular sealing members 2835 for sealing the
interface between the first upper sealing head 2725 and the first inner
sealing
mandrel 2720. The sealing members 2835 may comprise any number of
conventional commercially available annular sealing members such as, for
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example, o-rings, polypak seals or metal spring energized seals. In a
preferred
embodiment, the sealing members 2835 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for long axial strokes.
In a preferred embodiment, the first upper sealing head 2725 includes a
shoulder 2840 for supporting the first upper sealing head 2725 on the first
lower
sealing head 2730.
The first upper sealing head 2725 may be coupled to the first outer sealing
mandrel 2735 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty threaded connection, welding, amorphous bonding or a
standard threaded connection. In a preferred embodiment, the first upper
sealing
head 2725 is removably coupled to the first outer sealing mandrel 2735 by a
standard threaded connection. In a preferred embodiment, the mechanical
coupling between the first upper sealing head 2725 and the first outer sealing
mandre12735 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
mandre12735. 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
allov
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 seahng 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 mandre12740 includes one
or more sealing members 2860 for fluidicly sealing the interface between the
first
lower sealing head 2730 and the second inner sealing mandrel 2740. The sealing
members 2860 may comprise any number of conventional commercially available
sealing members such as, for example, o-rings, polypak seals or metal spring
energized seals. In a preferred embodiment, the sealing members 2860 comprise
polypak seals available from Parker Seals in order to optimally provide
sealing for
long axial strokes.
The first outer sealing mandrel 2735 is coupled to the first upper sealing
head 2725, the second upper sealing head 2745, the second outer sealing
mandrel
2755, and the expansion cone 2765. The first outer sealing mandrel 2735 is
also
movably coupled to the inner surface of the casing 2790 and the outer surface
of
the first lower sealing head 2730. In this manner, the first upper sealing
head
2725, first outer sealing mandrel 2735, second upper sealing head 2745, second
outer sealing mandrel 2755, and the expansion cone 2765 reciprocate in the
axial
direction. The radial clearance between the outer surface of the first outer
sealing
mandrel 2735 and the inner surface of the casing 2790 may range, for example,
from about 0.025 to 0.375 inches. In a preferred embodiment, the radial
clearance
between the outer surface of the first outer sealing mandrel 2735 and the
inner
surface of the casing 2790 ranges from about 0.025 to 0.125 inches in order to
optimally provide stabilization for the expansion cone 2765 during the
expansion
process. The radial clearance between the inner surface of the first outer
sealing
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 mandrel
2735
and the outer surface of the first lower sealing head 2730 ranges from about
0.005
to 0.01 inches in order to optimally provide minimal radial clearance.
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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
mandre12735 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 mandrel 2735 may be coupled to the second upper sealing head 2745
using
any number of conventional commercially available mechanical couplings such
as,
for example, oilfield country tubular goods specialty threaded connection,
welding,
amorphous bonding, or a standard threaded connection. In a preferred
embodiment, the first outer sealing mandrel 2735 is removably coupled to the
second upper sealing head 2745 by a standard threaded connection.
The second inner sealing mandrel 2740 is coupled to the first lower sealing
head 2730 and the second lower sealing head 2750. The second inner sealing
mandrel 2740 preferably comprises a substantially hollow tubular member or
members. The second inner sealing mandrel 2740 may be fabricated from any
number of conventional commercially available materials such as, for example,
oilfield country tubular goods, low alloy steel, carbon steel, stainless steel
or other
similar high strength materials. In a preferred embodiment, the second inner
sealing mandrel 2740 is fabricated from stainless steel in order to optimally
provide high strength, corrosion resistance, and low friction surfaces.
The second inner sealing mandrel 2740 may be coupled to the first lower
sealing head 2730 using any number of conventional commercially available
mechanical couplings such as, for example, oilfield country tubular goods
specialty
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threaded connection, welding, amorphous bonding, or a standard threaded
connection. In a preferred embodiment, the second inner sealing mandrel 2740
is
removably coupled to the first lower sealing head 2740 by a standard threaded
connection. The mechanical coupling between the second inner sealing mandrel
2740 and the first lower sealing head 2730 preferably includes sealing members
2860.
The second inner sealing 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 mandre12720 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 seal.ing 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 mandrel 2740
and
the inner surface of the casing 2790. In this manner, the second upper sealing
head 2745 reciprocates in the axial direction. The radial clearance between
the
inner cylindrical surface of the second upper sealing head 2745 and the outer
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surface of the second inner sealing mandrel 2740 may range, for example, from
about 0.0025 to 0.05 inches. In a preferred embodiment, the radial clearance
between the inner cylindrical surface of the second upper sealing head 2745
and
the outer surface of the second inner sealing mandrel 2740 ranges from about
0.005 to 0.01 inches in order to optimally provide minimal radial clearance.
The
radial clearance between the outer cylindrical surface of the second upper
sealing
head 2745 and the inner surface of the casing 2790 may range, for example,
from
about 0.025 to .375 inches. In a preferred embodiment, the radial clearance
between the outer cylindrical surface of the second upper sealing head 2745
and
the inner surface of the casing 2790 ranges from about 0.025 to 0.125 inches
in
order to optimally provide stabilization for the expansion cone 2765 during
the
expansion process.
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 seali.ng head 2745 is removably coupled to the first outer
sealing
mandrel 2735 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the second upper sealing head 2745 and the first
outer sealing mandrel 2735 includes one or more sealing members 2880 for
fluidicly sealing the interface between the second upper sealing head 2745 and
the
first outer sealing mandrel 2735. The sealing members 2880 may comprise anv
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 mandrel 2755 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, or a standard threaded
connection. In a preferred embodiment, the second upper sealing head 2745 is
removably coupled to the second outer sealing mandrel 2755 by a standard
threaded connection. In a preferred embodiment, the mechanical coupling
between the second upper sealing head 2745 and the second outer sealing
mandrel
2755 includes one or more sealing members 2885 for fluidicly sealing the
interface
between the second upper sealing head 2745 and the second outer sealing
mandrel
2755. The sealing members 2885 may comprise any number of conventional
commercially available sealing members such as, for example, o-rings, polypak
seals or metal spring energized seals. In a preferred embodiment, the sealing
members 2885 comprise polypak seals available from Parker Seals in order to
optimally provide sealing for long axial strokes.
The second lower sealing head 2750 is coupled to the second inner sealing
mandrel 2740 and the load 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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mandre12735, second upper sealinghead 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 mandre12755 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 embodiment, the second lower sealing head 2750 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The outer surface of the
second
lower sealing head 2750 preferably includes one or more annular sealing
members
2890 for sealing the interface between the second lower sealing head 2750 and
the
second outer sealing mandrel 2755. The sealing members 2891) 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
mandre12740 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 seahng 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 mandre12755 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 mandrel 2735, second upper sealing head 2745, second
outer sealing mandrel 2755, and the expansion cone 2765 reciprocate in the
axial
direction.
The radial clearance between the outer surface of the second 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 mandre12755 and the
inner
surface of the casing 2790 ranges from about 0.025 to 0.125 inches in order to
optimally provide stabilization for the expansion cone 2765 during the
expansion
process. The radial clearance between the inner surface of the second outer
sealing
mandrel 2755 and the outer surface of the second lower sealing head 2750 may
range, for example, from about 0.0025 to 0.05 inches. In a preferred
embodiment,
the radial clearance between the inner surface of the second outer sealing
mandrel
2755 and the outer surface of the second lower sealing'head 2750 ranges from
about 0.005 to 0.01 inches in order to optimally provide minimal radial
clearance.
The second outer sealing mandrel 2755 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The second
outer sealing mandrel 2755 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the second outer sealing mandrel 2755 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The second outer sealing mandrel 2755 may be coupled to the second upper
sealing head 2745 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
second outer sealing mandrel 2755 is removably coupled to the second upper
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sealing head 2745 by a standard threaded connection. The second outer sealing
mandre1.2755 may be coupled to the expansion cone 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 second outer sealing mandre12755 is
removably coupled to the expansion cone 2765 by a sta.n.dard threaded
connection.
The load mandre12760 is coupled to the second lower sealing head 2750 and
the mechanical slip body 2755. The load mandrel 2760 preferably comprises an
annular member having substantially cylindrical inner and outer surfaces. The
load mandrel 2760 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the load mandre12760 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces_
The load mandrel 2760 may be coupled to the second lower sealing head
2750 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods
specialty type threaded connection, ratchet=latch type threaded connection, or
a
standard threaded connection. In a preferred embodiment, the load mandrel 2760
is removably coupled to the second lower sealing head 2750 by a standard
threaded
connection. The load mandre12760 may be coupled to the mechanical slip body
2775 using any number of conventional commercially available mechanical
couplings such as, for example, driIlpipe 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 mandre12760
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
mandre12755,
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 time.s 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 embodi.ment, 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 gaIling. In a particularly preferred
embodiinent,
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 apreferred 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 2-785. The mechanical slip body
2775
preferably comprises a tubular niember 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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tungsten carbide mechanical slips, RTTS packer wicker type mechanical slips or
Mode13L retrievable bridge plug tungsten carbide upper mechanical slips. In a
preferred embodi.ment, the mechanical slips 2780 comprise RTTS packer tungsten
carbide mechanical slips available from Halliburton Energy Services in order
to
optimally provide resistance to axial movement of the casing 2790 and mandrel
launcher 2770 during the expansion process.
The drag blocks 2785 are coupled to the outside surface of the mechanical
slip body 2775. During operation of the apparatus 2700, the drag blocks 2785
prevent upward movement of the casing 2790 and mandrel launcher 2770. In this
manner, during the axial reciprocation of the expansion cone 2765, the casing
2790
and mandrel launcher 2770 are maintained in a substantially stationary
position.
In this manner, the mandrel launcher 2770 and casing 2790 are expanded in the
radial direction by the axial movement of the expansion cone 2765.
The drag blocks 2785 may comprise any number of conventional
commercially available mechanical slips such as, for example, RTTS packer
mechanical drag blocks or Model 3L retrievable bridge plug drag blocks. In a
preferred embodiment, the drag blocks 2785 comprise RTTS packer mechanical
drag blocks available from Halliburton Energy Services in order to optimally
provide resistance to axial movement of the casing 2790 and mandrel launcher
2770 during the expansion process_
The casing 2790 is coupled to the mandrel launcher 2770. The casing 2790
is further removably coupled to the mechanical slips 2780 and drag blocks
2785.
The casing 2790 preferably comprises a tubular member. The casing 2790 may be
fabricated from any number of conventional commercially available materials
such
as, for example, slotted tubulars, oilfield country tubular goods, low alloy
steel,
carbon steel, stainless steel or other similar high strength materials. In a
preferred
embodiment, the casing 2790 is fabricated from oilfield country tubular goods
available from various foreign and domestic steel mills in order to optimally
provide high strength using standardized materials. In a preferred embodiment,
the upper end of the casing 2790 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, driIling 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 fluiclic
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, drillillg 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 wellbore casing
ranges from about 400 to 10,000 in order to optimally provide contact pressure
for
activating the sealing members, provide optimal resistance to axial movement
of
the expanded casing, and optimally resist typical tensile and compressive
loads on
the expanded casing.
In a preferred embodiment, as the expansion cone 2765 nears the end of the
casing 2790, the operating pressure of the second fluidic material is reduced
in
order to minimize shock to the apparatus 2700. In an alternative embodiment,
the
apparatus 2700 includes a shock absorber for absorbing the shock created by
the
completion of the radial expansion of the casing 2790.
In a preferred embodiment, the reduced operating pressure of the second
fluidic material ranges from about 100 to 1,000 psi as the expansion cone 2765
nears the end of the casing 2790 in order to optimally provide reduced axial
movement and velocity of the expansion cone 2765. In a preferred embodiment,
the operating pressure of the second fluidic material is reduced during the
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 2790 acted upon during the radial
expansion
process. In this manner, the operating pressures can be reduced.
In an alternative embodiment, mechanical slips are positioned in an axial
location between the sealing sleeve 1915 and the first inner seali.ng 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 casing2790. 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 mandre13020, 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, asecond outer sealing mandre13060, 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 drillpipe 3005 may be coupled to the innerstring adapter 3010
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 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 driIl 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 coupli.ngs such
as,
for example, drillpipe connection, oilfield country tubular goods specialty
type
threaded connection, ratchet-latch type threaded connection or a standard
threaded connection. In a preferred embodiment, the sealing sleeve 3015 is
removably coupled to the first inner sealing 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 mandre13020 preferably comprises a substantially
hollow tubular member or members. The first inner sealing mandre13020 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
optilnally provide high strength, corrosion resistance, and low friction
surfaces.
The first inner sealing mandrel 3020 may be coupled to the sealing sleeve
3015 using any number of conventional commercially available mechanical
couplings such as, for example, drillpipe connection, oilfield country tubular
goods
specialty type threaded connection, ratchet-latch type threaded connection or
a
standard threaded connection. In a preferred embodiment, the first inner
sealing
mandrel 3020 is removably coupled to the sealing sleeve 3015 by a standard
threaded connection. The first inner sealing mandre13020 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 mandre13020 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, driIlpipe
connection, oilfield country tubular goods specialty type threaded connection,
ratchet-latch type threaded connection or a standard threaded connection. In a
preferred embodiment, the first inner sealing mandrel 3020 is removably
coupled
to the first lower sealing head 3035 by a standard threaded connection.
The first inner sealing mandrel 3020 preferably includes a fluid passage
3095 that is adapted to convey fluidic materials from the fluid passage 3090
into
the fluid passage 3100. In a preferred embodiment, the fluid passage 3095 is
adapted to convey fluidic materials such as, for example, water, drilling mud,
cement, epoxy, or lubricants at operating pressures and flow rates ranging
from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The first inner sealing mandrel 3020 further preferably includes fluid
passages 3110 that are adapted to convey fluidic materials from the fluid
passage
3095 into the pressure chambers of the hydraulic slips 3025. In this manner,
the
slips 3025 are activated upon the pressurization of the fluid 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, driIling fluids or lubricants at operating pressures and
flow
rates ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The first inner sealing mandrel 3020 further preferably includes fluid
passages 3115 that are adapted to convey fluidic materials from the fluid
passage
3095 into the first pressure chamber 3175 defined by the first upper sealing
head
3030, the first lower sealing head 3035, the first inner sealing mandrel 3020,
and
the first outer sealing mandrel 3040. During operation of the apparatus 3000,
pressurization of the pressure chamber 3175 causes the first upper sealing
head
3030, the first outer sealing mandre13040, the second upper sealing head 3050,
the
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second outer sealing mandrel 3060, and the expansion cone 3070 to move in an
axial direction.
The slips 3025 are coupled to the outside surface of the first inner sealing
mandrel 3020. During operation of the apparatus 3000,t the slips 3025 are
activated upon the pressurization.of the fluid passage 3095 into contact with
the
inside surface of the casing 3075. In this manner, the slips 3025 maintain the
casing 3075 in a substantially stationary position.
The slips 3025 preferably include fluid passages 3125, pressure chambers
3130, spring bias 3135, and slip members 3140. The slips 3025 may comprise any
number of conventional commercially available hydraulic slips such as, for
example, RTTS packer tungsten carbide hydraulic slips or Model 3L retrievable
bridge plug with hydraulic slips. In a preferred embodiment, the slips 3025
comprise RTTS packer tungsten carbide hydraulic slips available from
Halliburton
Energy Services in order to optimally provide resistance to axial movement of
the
casing 3075 during the expansion process.
The first upper sealing head 3030 is coupled to the first outer sealing
mandrel 3040, the second upper sealing head 3050, the second outer sealing
mandrel 3060, and the expansion cone 3070. The first upper sealing head 3030
is
also movably coupled to the outer surface of the first ianer sealing mandrel
3020
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 cyli.ndrical inner and outer surfaces. The first upper
sealing
head 3030 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy
steel, carbon steel, or other similar high strength materials. In a preferred
embodiment, the first upper sealing head 3030 is fabricated from stainless
steel in
order to optimally provide high strength, corrosion resistance, and low
friction
surfaces. The inner surface of the first upper sealing head 3030 preferably
includes one or more annular sealing members 3145 for sealing the interface
between the first upper sealing head 3030 and the first inner sealing mandrel
3020. The sealing members 3145 may comprise any number of conventional
commercially available annular seali.ng 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
mandrel 3040, second upper sealing head 3050, second outer sealing mandrel
3060,
and expansion cone 3070 on the first lower sealing head 3035. The first upper
sealing head 3030 may be coupled to the first outer sealing mandrel 3040 using
any
number of conventional commercially available mechanical couplings such as,
for
example, drillpipe connection, oilfield country tubular goods specialty type
threaded connection, or a standard threaded connection. In a preferred
embodiment, the first upper sealing head 3030 is removably coupled to the
first
outer sealing 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 upper sealing head
3030
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and the first outer sealing mandrel 3040. The sealing members 3155 may
comprise
any number of conventional commercially available sealing members such as, for
example, o-rings, polypak seals, or metal spring energized seals. In a
preferred
embodiment, the sealing members 3155 comprise polypak seals available from
Parker Seals in order to optimally. provide sealing for a long axial stroke.
The first lower sealing head 3035 is coupled to- the first inner sealing
mandrel 3020 and the second inner sealing mandrel 3045. The first lower
sealing
head 3035 is also movably coupled to the inner surface of the first outer
sealing
mandrel 3040. In this manner, the first upper sealing head 3030, first outer
sealing mandrel 3040, second upper sealing head 3050, second outer sealing
mandrel 3060, and expansion cone 3070 reciprocate in the axial direction. The
radial clearance between the outer surface of the first lower sealing head
3035 and
the inner surface of the first outer sealing mandrel 3040 may range, for
example,
from about 0.0025 to 0.05 inches. In a preferred embodiment, the radial
clearance
between the outer surface of the first lower sealing head 3035 and the inner
surface of the outer sealing mandrel 3040 ranges from about 0.005 to 0.01
inches
in order to optimally provide minimal radial clearance.
The first lower sealing head 3035 preferably comprises an annular member
having substantially cylindrical inner and outer surfaces. The first lower
sealing
head 3035 may be fabricated from any number of conventional commercially
available materials such as, for example, oilfield country tubular goods, low
alloy
steel, carbon steel, stainless steel or other similar high strength materials.
In a
preferred embodiment, the first lower sealing head 3035 is fabricated from
stainless steel in order to optimally provide high strength, corrosion
resistance,
and low friction surfaces. The outer surface of the first lower sealing head
3035
preferably includes one or more annular sealing members 3160 for sealing the
interface between the first lower sealing head 3035 and the first outer
sealing
mandrel 3040. The sealing members 3160 may comprise any number of
conventional commercially available annular sealing members such as, for
example, o-rings, polypak seals, or metal spring energized seals. In a
preferred
embodiment, the sealing members 3160 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
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The first lower sealing head 3035 may be coupled to the first inner sealing
mandrel 3020 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
first lower sealing head 3035 is removably coupled to the first inner sealing
mandrel 3020 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the first lower sealing head 3035 and the first
inner
sealing mandrel 3020 includes one or more sealing members 3165 for fluidicly
sealing the interface between the first lower sealing head 3035 and the first
inner
sealing mandrel 3020. The sealing members 3165 may comprise any number of
conventional commercially available sealingmembers 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 seali.ng head 3035 and
the
second inner sealing mandrel 3045. The sealing members 3170 may comprise any
number of conventional commercially available sealing members such as, for
example, o-rings, polypak seals or metal spring energized seals. In a
preferred
embodiment, the sealing members 3170 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
The first outer sealing mandre13040 is coupled to the first upper sealing
head 3030 and the second upper sealing head 3050. The first outer sealing
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mandrel 3040 is also movably coupled to the inner surface of the casing 3075
and
the outer surface of the first lower sealing head 3035. In this manner, the
first
upper sealing head 3030, first outer sealing mandrel 3040, second upper
sealing
head 3050, second outer sealing mandrel 3060, and the expansion cone 3070
reciprocate in the axial direction. The radial clearance between the outer
surface
of the first outer sealing mandrel 3040 and the inner surface of the casing
3075
may range, for example, from about 0.025 to 0.375 inches. In a preferred
embodiment, the radial clearance between the outer surface of the first outer
sealing 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 mandrel 3040 and the outer surface of the
first
lower sealing head 3035 may range, for example, from about 0.005 to 0.125
inches.
In a preferred embodiment, the radial clearance between the inner surface of
the
first outer seahng mandrel 3040 and the outer surface of the first lower
sealing
head 3035 ranges from about 0.005 to 0.01 inches in order to optimally provide
minimal radial clearance.
The first outer sealing mandrel 3040 preferably comprises an annular
member having substantially cylindrical inner and outer surfaces. The first
outer
sealing mandrel 3040 may be fabricated from any number of conventional
commercially available materials such as, for example, oilfield country
tubular
goods, low alloy steel, carbon steel, stainless steel or other similar high
strength
materials. In a preferred embodiment, the first outer sealing mandrel 3040 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces.
The first outer sealing mandrel 3040 may be coupled to the first upper
sealing head 3030 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
first outer sealing mandrel 3040 is removably coupled to the first upper
sealing
head 3030 by a standard threaded connection. In a preferred embodiment, the
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mechanical coupling between the first outer sealing mandre13040 and the first
upper sealing head 3030 includes one or more seali.ng members 3180 for seaiing
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 commerciallyavailablesealingmembers such as, for example, o-
rings,
polypak seals or metal spring energized seals. In a preferred embodiment, the
sealing members 3180 comprise polypak seals available from Parker Seals in
order
to optimally provide sealing for a long axial stroke.
The first outer sealing mandrel 3040 may be coupled to the second upper
sealing head 3050 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection, or a standard threaded connection. In a preferred embodiment, the
first outer sealing mandrel 3040 is removably coupled to the second upper
sealing
head 3050 by a standard threaded connection. In a preferred embodiment, the
mechanical coupling between the first outer sealing mandrel 3040 and the
second
upper sealing head 3050 includes one or more sealing members 3185 for sealing
the interface between the first outer sealing mandrel 3040 and the second
upper
sealing head 3050. The sealing members 3185 may comprise any number of
conventional commercially available sealing members such as, for example, o-
rings,
polypak seals or metal spring energized seals. In a preferred embodiment, the
sealing members 3185 comprise polypak seals available from Parker Seals in
order
to optimally provide sealing for a long axial stroke.
The second inner sealing 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 emboditnent, the second inner
seali.ng mandrel 3045 is fabricated from-stainless steel in order to optimally
provide high strength, corrosion resistance, and low friction surfaces.
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The second inner sealing mandrel 3045 may be coupled to the first lower
sealing head 3035 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection or a standard threaded connection. In a preferred embodiment, the
second inner sealing mandrel 3045 is removably coupled to the first lower
sealing
head 3035 by a standard threaded connection. The second inner sealing mandrel
3045 may be coupled to the second lower sealing head 3055 using any number of
conventional commercially available mechanical couplings such as, for example,
drillpipe connection, oilfield country tubular goods specialty type threaded
connection, ratchet-latch type connection, or a standard threaded connection.
In
a preferred embodiment, the second inner sealing mandrel 3045 is removably
coupled to the second lower sealing head 3055 by a standard threaded
connection.
The second inner sealing mandrel 3045 preferably includes a fluid passage
3100 that is adapted to convey fluidic materials from the fluid passage 3095
into
the fluid passage 3105. In a preferred embodiment, the fluid passage 3100 is
adapted to convey fluidic materials such as, for example, cement, epoxy,
water,
drilling mud or lubricants at operating pressures and flow rates ranging from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute.
The second inner sealing mandrel 3045 further preferably includes fluid
passages 3120 that are adapted to convey fluidic materials from the fluid
passage
3100 into the second pressure chamber 3190 defined by the second upper sealing
head 3050, the second lower sealing head 3055, the second inner sealing
mandrel
3045, and the second outer sealing mandrel 3060. During operation of the
apparatus 3000, pressurization of the second pressure chamber 3190 causes the
first upper sealing head 3030, the first outer sealing mandrel 3040, the
second
upper sealing head 3050, the second outer sealing mandrel 3060, and the
expansion cone 3070 to move in an axial direction.
The second upper sealing head 3050 is coupled to the first outer staling
mandrel 3040 and the second outer seali.ng mandrel 3060. The second upper
sealing head 3050 is also movably coupled to the outer surface of the second
inner
sealingmandrel 3045 and the inner surface of the casing3075. In this manner,
the
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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 mandre13045 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 conventional
conunercially 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 prefei-red embodiment, the second upper sealing head 3050 is
fabricated from stainless steel in order to optimally provide high strength,
corrosion resistance, and low friction surfaces. The inner surface of the
second
upper sealing head 3050 preferably includes one or more annular sealing
members
3195 for sealing the interface between the second upper sealing head 3050 and
the
second inner sealing mandrel 3045. The sealing members 3195 may comprise any
number of conventional commercially available annular sealing members such as,
for example, o-rings, polypak seals or metal spring energized seals. In a
preferred
embodiment, the sealing members 3195 comprise polypak seals available from
Parker Seals in order to optimally provide sealing for a long axial stroke.
In a preferred embodiment, the second upper sealing head 3050 includes a
shoulder 3200 for supporting the first upper sealing head 3030, first outer
sealing
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mandrel 3040, second upper sealing head 3050, second outer sealing mandrel
3060,
and expansion cone 3070 on the second lower sealing head 3055.
The second upper sealing head 3050 may be coupled to the first outer
sealing mandrel 3040 using any number of conventional commercially available
mechanical couplings such as, for example, drillpipe connection, oilfield
country
tubular goods specialty type threaded connection, ratchet-latch type threaded
connection, or a standard threaded connection. In a preferred embodiment, the
second upper sealing head 3050 is removably coupled to the first outer sealing
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 seali.ng 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 nuinber 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 sealingmandrel
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
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,
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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 mandre13060 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 mandrel 3045
includes one or more seali.ng members 3215 for fluidicly sealing the interface
between the second lower sealing head 3055 and the second inner sealing
mandrel
3045. The sealing members 3215 may comprise any number of conventional
commercially available sealing members such as, for example, o-rings, polypak
seals or metal spring energized seals. In a preferred embodiment, the sealing
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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 couplingbetween the second lower sealinghead 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 mandrel 3040, second upper sealing head
3050, second outer sealing maiidrel 3060, and the expansion cone 3070
reciprocate
in the axial direction. The radial clearance between the outer surface of the
second outer sealing mandrel 3060 and the inner surface of the casing 3075 may
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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 seali.ng
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 optimaIly
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
connection. In a preferred embodiment, the second outer sealing mandre13060 is
removably coupled to the expansion cone 30-70 by a standard threaded
connection.
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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 mandre13045, 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 mandre13040, the
second
upper seali.ng 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 mandre13065 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 mandre13065 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.
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
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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 seali.ng 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 sealinghead 3050, second outer sealing mandrel 3060,
and the expansion cone 3070 reciprocate in the axial direction. The
reciprocation
of the expansion cone 3070 causes the casing 3075 to expand in the radial
direction_
The expansion cone 3070 preferably comprises an annular member having
substantially cylindrical inner and conical outer surfaces. The outside radius
of
the outside conical surface may range, for example, from about 2 to 34 inches.
In
a preferred embodiment, the outside radius of the outside conical surface
ranges
from about 3 to 28 inches in order to optimally provide an expansion cone 3070
for
expanding typical casings. The axial length of the expansion cone 3070 may
range,
for example, from about 2 to 8 times the maximum outer diameter of the
expansion cone 3070. In a preferred embodiment, the axial length of the
expansion
cone 3070 ranges from about 3 to 5 times the maximum outer diameter of the
expansion cone 3070 in order to optimally provide stabilization and
centralization
of the expansion cone 3070 during the expansion process. In a particularly
preferred embodiment, the maximum outside diameter of the expansion cone 3070
is between about 95 to 99 % of the inside diameter of the existing wellbore
that the
casing 3075 will be joined with. In a preferred embodiment, the angle of
attack of
the expansion cone 3070 ranges from about 5 to 30 degrees in order to
optimally
balance the frictional forces with the radial expansion forces.
The expansion cone 3070 may be fabricated from any number of
conventional commercially available materials such as, for example, machine
tool
steel, nitride steel, titanium, tungsten carbide, ceramics, or other similar
high
strength materials. In a preferred embodiment, the expansion cone 3070 is
fabricated from D2 machine tool steel in order to optimally provide high
strength
and resistance to wear and galling. In a particularly preferred embodiment,
the
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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 expansioi- of the
thin
walled section 3240 of casing 3075 into the thin walled section of the
existing
wellbore casing results in a wellbore casing having a substantially constant
inside
diameter.
The annular sealing member 3245 may be fabricated from any number of
conventional commercially available sealing materials such as, for example,
epoxy,
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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 resistannce_ The outside diameter of the annular
sealing
member 3245 preferably ranges from about 70 to 95 % of the inside diameter of
the
lower section of the wellbore casing that the casing 3075 is joined to. In
this
manner, after radial expansion, the annular sealing member 3245 optimally
provides a fluidic seal and also preferably optimally provides sufficient
frictional
force with the inside surface of the existing section of wellbore casing
during the
radial expansion of the casing 3075 to support the casing 3075.
In a preferred embodiment, the lower end 3250 of the casing 3075 includes
a thin wall section 3255 and an outer annular sealing member 3260. In a
preferred
embodiment, the wall thickness of the thin wall section 3255 is about 50 to
100 %
of the regular wall thickness of the casing 3075. In this manner, the lower
end
3250 of the casing 3075 may be easily expanded and deformed. Furthermore, in
this manner, an other section of casing may be easily joined with the lower
end
3250 of the casing 3075 using a radial expansion process. In a preferred
embodiment, the upper end of the other section of casing also includes a thin
wall
section. In this manner, the radial expansion of the thin walled section of
the
upper end of the other casing into the thin walled section 3255 of the lower
end
3250 of the casing 3075 results in a wellbore casing having a substantially
constant
inside diameter.
The upper annular sealing member 3245 may be fabricated from any
number of conventional commercially available sealing materials such as, for
example, epoxy, rubber, metal or plastic. In a preferred embodiment, the upper
annular sealing member 3245 is fabricated from Stratalock epoxy in order to
optimally provide compressibility and resistance to wear. The outside diameter
of
the upper annular sealing member 3245 preferably ranges from about 70 to 95 %
of the inside diameter of the lower section of the existing wellbore casing
that the
casing 3075 is joined to. In this manner, after radial expansion, the upper
annular
seali.ngmember 3245 preferably provides a fluidic seal and also preferably
provides
sufficient frictional force with the inside wall of the wellbore during the
radial
expansion of the casing 3075 to support the casing 3075.
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The lower annular sealing member 3260 may be fabricated from any
number of conventional commercially available sealing materials such as, for
example, epoxy, rubber, metal or plastic. In a preferred embodiment, the lower
annular sealing member 3260 is fabricated from StrataLock epoxy in order to
optimally provide compressibility and resistance to wear. The outside diameter
of
the lower annular sealing member 3260 preferably ranges from about 70 to 95 %
of the inside diameter of the lower section of the existing wellbore casing
that the
casing 3075 is joined to. In this manner, the lower annular sealing member
3260
preferably provides a fluidic seal and also preferably provides sufficient
frictional
force with the inside wall of the wellbore during the radial expansion of the
casing
3075 to support the casing 3075.
During operation, the apparatus 3000 is preferably positioned in a wellbore
with the upper end 3235 of the casing 3075 positioned in an overlapping
relationship with the lower end of an existing wellbore casing. In a
particularly
preferred embodiment, the thin wall section 3240 of the casing 3075 is
positioned
in opposing overlapping relation with the thin wall section and outer annular
sealing member of the lower end of the existing section of wellbore casing. In
this
manner, the radial expansion of the casing 3075 will compress the thin wall
sections and annular compressible members of the upper end 3235 of the casing
3075 and the lower end of the existing wellbore casing into intimate contact.
During the positioning of the apparatus 3000 in the wellbore, the casing 3000
is
preferably supported by the expansion cone 3070.
After positioning the apparatus 3000, a first fluidic material is then pumped
into the fluid passage 3080. The first fluidic material may comprise any
number
of conventional commercially available materials such as, for example,
drilling
mud, water, epoxy, cement, slag mix or lubricants. In a preferred embodiment,
the
first fluidic material comprises a hardenable fluidic sealing material such
as, for
example, cement, epoxy, or slag mix in order to optiunally 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
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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 frst fluidic material then preferably fills the annular
region
between the outside of the apparatus 3000 and the interior walls of the
wellbore.
The plug 3230 is then introduced into the fluid passage 3080. The plug 3230
lodges in the throat passage 3225 and fluidicly isolates and blocks off the
fluid
passage 3100. In a preferred embodiment, a couple of volumes of a non-
hardenable
fluidic material are then pumped into the fluid passage 3080 in order to
remove
any hardenable fluidic material contained within and to ensure that none of
the
fluid passages are blocked.
A second fluidic material is then pumped into the fluid passage 3080. The
second fluidic material may comprise any number of conventional commercially
available materials such as, for example, water, drilling gases, drilling mud
or
lubricant. In a preferred embodiment, the second fluidic material comprises a
non-
hardenable fluidic material such as, for example, water, drilling mud,
drilling
gases, or lubricant in order to optimally provide pressurization of the
pressure
chambers 3175 and 3190.
The second fluidic material may be pumped into the fluid passage 3080 at
operating pressures and flow rates ranging, for example, from about 0 to 4,500
psi
and 0 to 4,500 gallons/minute. In a preferred embodiment, the second fluidic
material is pumped into the fluid passage 3080 at operating pressures and flow
rates ranging from about 0 to 3,500 psi and 0 to 1,200 gallons/minute in order
to
optimally provide operational efficiency.
The second fluidic material pumped into the fluid passage 3080 passes
through the fluid passages 3085, 3090, 3095, 3100 and into the pressure
chambers
3130 of the slips 3025, and into the pressure chambers 3175 and 3190.
Continued
pumping of the second fluidic material pressurizes the pressure chambers 3130,
3175, and 3190.
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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 seali.ng mandrel 3040, second upper
sealing
head 3050, second outer sealing mandrel 3060, and expansion cone 3070 to move
in an axial direction relative to the casing 3075. In this manner, the
expansion
cone 3070 will cause the casing 3075 to expand in the radial direction,
beginning
with the lower end 3250 of the casing 3075.
During the radial expansion process, the casing 3075 is prevented from
moving in an upward direction by the slips 3025. A length of the casing 3075
is
then expanded in the radial direction through the pressurization of the
pressure
chambers 3175 and 3190. The length of the casing 3075 that is expanded during
the expansion process will be proportional to the stroke length of the first
upper
sealing head 3030, first outer sealing mandrel 3040, second upper sealing head
3050, and expansion cone 3070.
Upon the completion of a stroke, the operating pressure of the second fluidic
material is reduced and the first upper sealing head 3030, first outer sealing
mandrel 3040, second upper sealinghead 3050, second outer sealingmandre13060,
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 driilpipe 3075 is preferably adjusted throughout the
radial expansion process in order to maintain the overlapping relationship
between
the thin walled sections of the lower end of the existing wellbore casing and
the
upper end of the casing 3235. In a preferred embodiment, the stroking of the
expansion cone 3070 is then repeated, as necessary, until the thin waIled
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
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constant inside diameter. This process may then be repeated for the entirety
of
the wellbore to provide a wellbore casing thousands of feet in length having a
substantially constant inside diameter.
In a preferred embodiment, during the final stroke of the expansion cone
3070, the slips 3025 are positioned as close as possible to the thin walled
section
3240 of the upper end 3235 of the casing 3075 in order minimize slippage
between
the casing 3075 and the existing wellbore casing at the end of the radial
expansion
process_ Alternatively, or in addition, the outside diameter of the upper
annular
sealing member 3245 is selected to ensure sufficient interference fit with the
inside
diameter of the lower end of the existing casing to prevent axial displacement
of
the casing 3075 during the final stroke. Alternatively, or in addition, the
outside
diameter of the lower annular sealing member 3260 is selected to provide an
interference fit with the inside walls of the wellbore at an earlier point in
the radial
expansion process so as to prevent further axial displacement of the casing
3075.
In this final alternative, the interference fit is preferably selected to
permit
expansion of the casing 3075 by pulling the expansion cone 3070 out of the
wellbore, without having to pressurize the pressure chambers 3175 and 3190.
During the radial expansion process, the pressurized areas of the apparatus
3000 are preferably limited to the fluid passages 3080, 3085, 3090, 3095,
3100,
3110, 3115, 3120, the pressure chambers 3130 within the slips 3025, and the
pressure chambers 3175 and 3190. No fluid pressure acts directly on the casing
3075. This permits the use of operating pressures higher than the casing 3075
could normally withstand.
Once the casing 3075 has been completely expanded off of the expansion
cone 3070, the remaining portions of the apparatus 3000 are removed from the
wellbore. In a preferred embodiment, the contact pressure between the deformed
thin wall sections and compressible annular members of the lower end of the
existing casing and the upper end 3235 of the casing 3075 ranges 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,
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3090, 3095, 3100, 3110, 3115, and 3120, the pressure chambers 3130 of the
slips
3025 and the pressure chambers 3175 and 3190 of the apparatus 3000.
In a preferred embodiment, as required, the annular body of hardenable
fluidic material is then allowed to cure to form a rigid outer annular body
about
the expanded casing 3075. In the=case where the casing 3075 is slotted, the
cured
fluidic material preferably permeates and envelops the expanded casing 3075.
The
resulting new section of wellbore casing includes the expanded casing 3075 and
the
rigid outer annular body. The overlapping joint between the pre-existing
wellbore
casing and the expanded casing 3075 includes the deformed thin wall sections
and
the compressible outer annular bodies. The inner diameter of the resulting
combined wellbore casings is substantially constant. In this manner, a mono-
diameter wellbore casing is formed. This process of expanding overlapping
tubular
members having thin wall end portions with compressible annular bodies into
contact can be repeated for the entire length of a wellbore. In this manner, a
mono-diameter wellbore casing can be provided for thousands of feet in a
subterranean formation.
In a preferred embodiment, as the expansion cone 3070 nears the upper end
3235 of the casing 3075, the operating flow rate of the second fluidic
material is
reduced in order to minimize shock to the apparatus 3000. In an alternative
embodiment, the apparatus 3000 includes ashock 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
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.
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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 ofsolid tubular casing such as, for example,
oilfeld
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
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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.
The seals 3340 prevent the passage of fluids and other materials within the
annular region 3365 between the solid casings 3335 and 3350 and the wellbore
3305. The seals 3340 may comprise any number of conventional commercially
available sealing materials suitable for sealing a casing in a wellbore such
as, for
example, lead, rubber or epoxy. In a preferred embodiment, the seals 3340
comprise Stratalok epoxy material available from Halliburton Energy Services.
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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.
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
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3345 may be expanded in a radial direction using any number of conventional
comrnercially 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 controllingthe 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.
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.
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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
fllled
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.
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
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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 mandre13510, 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 wellbore 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
driIipipe 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.
The mandre13510 is coupled to and supported by the support member 3505.
The mandre13510 is also coupled to and supports the mandrel launcher 3515 and
tubular member 3525. The mandre13510 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
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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.
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 niix 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
to optimally facitiate 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
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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
the mandrel 3510. The tubular member 3525 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, automotive
grade steel, or plastic tubing/casing. In a preferred embodiment, the tubular
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,
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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 nlix 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
- 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
driIling and casing operations.
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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 hydraulically 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 mandre13510. 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
mandrel 3510. 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
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
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of the pressure chamber 3550 preferably causes the tubular member 3525 to be
extruded off of the mandre13510.
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
may be 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 sea13560 prevents foreign materials from entering
the interior region of the tubular member 3525. The cup sea13560 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 mandre13510 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,
:LubriplateTM,
chlorine based lubricants, oil based lubricants or Climax 1500 Antisieze
(3100).
In a preferred embodiment, the lubricant 3565 comprises Climax 1500 Antisieze
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(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 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 3570 are molded from Stratalock epoxy available from
Halliburton Energy Services in Dallas, TX in order to optimally provide a load
bearing interference fit between the end 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-existingcasing3590. In apreferred 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.
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 positioned in an overlapping relationship with the lower end 3585 of the
preexisting section of casing 3590. In a preferred embodiment, the apparatus
3500
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is initially positioned in the wellbore 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
mandre13510.
As illustrated in Figure 22B, a fluidic materia13595 is then pumped into the
first fluid passage 3540. The fluidic materia13595 is preferably conveyed from
the
ftrst 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 com.mercially
available fluidic materials such as, for example, drillingmud, water, cement,
epoxy
or slag mix. The fluidic materia13595 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 materia13595 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 materia13595 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
pressure chamber 3550 wiIl then cause the tubular member 3525 to extrude off
of
the mandre13510 as illustrated in Figure 22D. For typical tubular members
3525,
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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 materia13595 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 mandrel 3510,
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 mandrel 3510, 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 mandrel 3510. At this point, the
extrusion
of the tubular member 3525 off of the mandrel 3510 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
newly drilled section of wellbore is created by the constant downward feeding
of
the expanded tubular member 3525 off of the mandrel 3510.
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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 1-21, 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.
Referring now to FIGS. 23A, 23B and 23C, an apparatus 3700 for expanding
a tubular member wiIl be described. In a preferred embodiment, the apparatus
3700 includes asupport member 3705, a packer 3710, a first fluid conduit 3715,
an
annular fluid passage 3720, fluid inlets 3725, an annular seal 3730, a second
fluid
conduit 3735, a fluid passage 3740, a mandrel 3745, a mandrel launcher 3750, a
tubular member 3755, slips 3760, and seals 3765. In a preferred embodiment,
the
apparatus 3700 is used to radially expand the tubular member 3755. In this
manner, the apparatus 3700 may be used to form a wellbore casing, line a
wellbore
casing, form a pipeline, Iine a pipeline, form a structural support member, or
repair
a wellbore casing, pipeline or structural support member. In a preferred
embodiment, the apparatus 3700 is used to clad at least a portion of the
tubular
member 3755 onto a preexisting tubular member.
The support member 3705 is preferably coupled to the packer 3710 and the
mandrel launcher 3750. The support member 3705 preferably comprises a tubular
member fabricated from any number of conventional commercially available
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materials such as, for example, oilfield country tubular goods, low alloy
steel,
carbon steel, or stainless steel. The support member 3705 is preferably
selected
to fit through a preexisting section of wellbore casing 3770. In this manner,
the
apparatus 3700 may be positioned within the wellbore casing 3770. In a
preferred
embodiment, the support member 3705 is releasably coupled to the mandrel
launcher 3750. In this manner, the support member 3705 may be decoupled from
the mandrel launcher 3750 upon the completion of an extrusion operation.
The packer 3710 is coupled to the support member 3705 and the first fluid
conduit 3715. The packer 3710 preferably provides a fluid seal between the
outside surface of the first fluid conduit 3715 and the inside surface of the
support
member 3705. In this manner, the packer 3710 preferably seals off and, in
combination with the support member 3705, first fluid conduit 3715, second
fluid
conduit 3735, and mandrel 3745, defines an annular chamber 3775. The packer
3710 may comprise any number of conventional commercially available packers
modified in accordance with the teachings of the present disclosure.
The first fluid conduit 3715 is coupled to the packer 3710 and the annular
seal 3730. The first fluid conduit 3715 preferably comprises an annular member
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 first fluid conduit 3715
includes
one or more fluid inlets 3725 for conveying fluidic materials from the annular
fluid
passage 3720 into the chamber 3775.
The annular fluid passage 3720 is def'med by and positioned between the
interior surface of the first fluid conduit 3715 and the interior surface of
the
second fluid conduit 3735. The annular fluid passage 3720 is preferably
adapted
to convey fluidic materials such as cement, water, epoxy, lubricants, and slag
mix
at operating pressures and flow rates ranging from about 0 to 9,000 psi and 0
to
3,000 gallons/minute in order to optimally provide operational efficiency.
The fluid inlets 3725 are positioned in an end portion of the first fluid
conduit 3715. The fluid inlets 3725 preferably are adapted to convey fluidic
materials such as cement, water, epoxy, lubricants, and slag mix at operating
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pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute in order to optimally provide operational efficiency.
The annular seal 3730 is coupled to the first fluid conduit 3715 and the
second fluid conduit 3735. The annular seal 3730 preferably provides a fluid
seal
between the interior surface of the first fluid conduit 3715 and the exterior
surface
of the second fluid conduit 3735. The annular sea13730 preferably provides a
fluid
seal between the interior surface of the first fluid conduit 3715 and the
exterior
surface of the second fluid conduit 3735 during relative axial motion of the
first
fluid conduit 3715 and the second fluid conduit 3735. The annular seal 3730
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 annular sea13730 comprises a polypak seal available from
Parker
Seals in order to optimally provide sealing for axial motion.
The second fluid conduit 3735 is coupled to the annular seal 3730 and the
mandrel 3745. The second fluid conduit preferably comprises a tubular member
fabricated from any number of conventional commercially available materials
such
as, for example, coiled tubing, oilfield country tubular goods, low alloy
steel,
stainless steel, or low carbon steel. In a preferred embodiment, the second
fluid
conduit 3735 is adapted to convey fluidic materials such as cement, water,
epoxy,
lubricants, and slag mix at operating pressures and flow rates ranging from
about
0 to 9,000 psi and 0 to 3,000 gallons/minute in order to optimally provide
operational efficiency.
The fluid passage 3740 is coupled to the second fluid conduit 3735 and the
mandrel 3745. In a preferred embodiment, the fluid passage 3740 is adapted to
convey fluidic materials such as cement, water, epoxy, lubricants, and slag
mix at
operating pressures and flow rates ranging from about 0 to 9,000 psi and 0 to
3,000
gallons/minute in order to optimally provide operational efficiency.
The mandrel 3745 is coupled to the second fluid conduit 3735 and the
mandrel launcher 3750. The mandrel 3745 preferably comprise an annular
member having a conic section fabricated from any number of conventional
commercially available materials such as, for example, carbon steel, tool
steel,
ceramics, or composite materials. In a preferred embodiment, the angle of
attack
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the conic section of the mandrel 3745 ranges from about 10 to 30 degrees in
order
to optimally expand the mandrel launcher 3750 and tubular member 3755 in the
radial direction. In a preferred embodiment, the surface hardness of the conic
section of the mandrel 3745 ranges from about 50 Rockwell C to 70 Rockwell C.
In a particularly preferred embodiment, the surface hardness of the outer
surface
of the conic section of the mandrel 3745 ranges from about 58 Rockwell C to 62
Rockwell C in order to optimally provide high yield strength. In an
alternative
embodiment, the mandrel 3745 is expandable in order to further optimally
augment the radial expansion process.
The mandrel launcher 3750 is coupled to the support member 3705, the
mandrel 3745, and the tubular member 3755. The mandrel launcher 3750
preferably comprise a tubular member having a variable cross-section and a
reduced wall thickness in order to facilitate the radial expansion process. In
a
preferred embodiment, the cross-sectional area of the mandrel launcher 3750 at
one end is adapted to mate with the mandrel 3745, and at the other end, the
cross-
sectional area of the mandrel launcher 3750 is adapted to match the cross-
sectional
area of the tubular member 3755. In a preferred embodiment, the wall thickness
of the mandrel launcher 3750 ranges from about 50 to 100 % of the wall
thickness
of the tubular member 3755 in order to facilitate the initiation of the radial
expansion process.
The mandrel launcher 3750 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, low allow steel, stainless steel, or carbon steel. In a
preferred embodiment, the mandrel launcher 3750 is fabricated from oilfield
country tubular goods having higher strength but lower wa11 thickness than the
tubular member 3755 in order to optimally match the burst strength of the
tubular
member 3755. In a preferred embodiment, the mandrel launcher 3750 is
removably coupled to the tubular member 3755. In this manner, the mandrel
launcher 3750 may be removed from the wellbore 3780 upon the completion of an
extrusion operation.
The tubular member 3755 is coupled to the mandrel launcher, the slips 3760
and the seals 3765. The tubular member 3755 preferably comprises a tubular
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member fabricated from any number of conventional commercially available
materials such as, for example, low alloy steel, carbon steel, stainless
steel, or
oilfield country tubular goods. In a preferred embodiment, the tubular member
3755 is fabricated from oilfield country tubular goods.
The slips 3760 are coupled to the outside surface of the tubular member
3755. The slips 3760 preferably are adapted to couple to the interior walls of
a
casing, pipeline or other structure upon the radial expansion of the tubular
member 3755. In this manner, the slips 3760 provide structural support for the
expanded tubular member 3755. The slips 3760 may comprise any number of
conventional commercially available slips, modified in accordance with the
teachings of the present disclosure.
The seals 3765 are coupled to the outside surface of the tubular member
3755. The seals 3765 preferably provide a fluidic seal between the outside
surface
of the expanded tubular member 3755 and the interior walls of a casing,
pipeline
or other structure upon the radial expansion of the tubular member 3755. In
this
manner, the seals 3765 provide a fluidic seal for the expanded tubular member
3755. The seals 3765 may comprise any number of conventional comrnerci.ally
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 3765 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 optimally provide load carrying
capacity
to withstand the range of typical tensile and compressive loads.
During operation of the apparatus 3700, the apparatus 3700 is preferably
lowered into a wellbore 3780 having a preexisting section of wellbore casing
3770.
In a preferred embodiment, the apparatus 3700 is positioned with at least a
portion of the tubular member 3755 overlapping with a portion of the wellbore
casing 3770. In this manner, the radial expansion of the tubular member 3755
will
preferably cause the outside surface of the expanded tubular member 3755 to
couple with the inside surface of the wellbore casing 3770. In a preferred
embodiment, the radial expansion of the tubular member 3755 will also cause
the
slips 3760 and seals 3765 to engage with the interior surface of the wellbore
casing
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3770. In this manner, the expanded tubular member 3755 is provided with
enhanced structural support by the slips 3760 and an enhanced fluid seal by
the
seals 3765.
As illustrated in FIG. 23B, after placement of the apparatus 3700 in an
overlapping relationship with the wellbore casing 3770, a fluidic material
3785 is
preferably pumped into the chamber 3775 using the fluid passage 3720 and the
inlet passages 3725. In a preferred embodiment, the fluidic material is pumped
into the chamber 3775 at operating pressures and flow rates ranging from about
0 to 9,000 psi and 0 to 3,000 gallons/minute in order to optimally provide
10. operational efficiency. The pumped fluidic material 3785 increase the
operating
pressure within the chamber 3775. The increased operating pressure in the
chamber 3775 then causes the mandrel 3745 to extrude the mandrel launcher 3750
and tubular member 3755 off of the face of the mandrel 3745. The extrusion of
the
mandrel launcher 3750 and tubular member 3755 off of the face of the mandrel
3745 causes the mandrel launcher 3750 and tubular member 3755 to expand in the
radial direction. Continued pumping of the fluidic material 3785 preferably
causes
the entire length of the tubular member 3755 to expand in the radial-
direction.
In a preferred embodiment, the pumping rate and pressure of the fluid.ic
material 3785 is reduced during the latter stages of the extrusion process in
order
to minimize shock to the apparatus 3700. In a preferred embodiment, the
apparatus 3700 includes shock absorbers for absorbing the shock caused by the
completion of the extrusion process.
In a preferred embodiment, the extrusion process causes the mandrel 3745
to move in an axial direction 3785. During the axial movement of the mandrel,
in
a preferred embodiment, the fluid passage 3740 conveys fluidic material 3790
displaced by the moving mandrel 3745 out of the wellbore 3780. In this manner,
the operational efficiency and speed of the extrusion process is enhanced.
In a preferred embodiment, the extrusion process includes the injection of
ahardenable fluidic material into the annular region between the tubular
member
3755 and the bore hole 3780. In this manner, a hardened sealing layer is
provided
between the expanded tubular member 3755 and the interior walls of the
wellbore
3780.
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As illustrated in FIG. 23C, in a preferred embodiment, upon the completion
of the extrusion process, the support member 3705, packer 3710, first fluid
conduit
3715, annular seal 3730, second fluid conduit 3735, mandrel 3745, and mandrel
launcher 3750 are moved from the wellbore 3780.
In an alternative embodiment, the apparatus 3700 is used to repair a
preexisting wellbore casing, pipeline, or structural support. In this
alternative
embodiment, both ends of the tubular member 3755 preferably include slips 3760
and seals 3765.
In an alternative embodiment, the apparatus 3700 is used to form a tubular
structural support for a building or offshore structure.
Referring now to FIGS. 24A, 24B, 24C, 24D, and 24E, an apparatus 3900 for
expanding a tubular member will be described. In a preferred embodiment, the
apparatus 3900 includes a support member 3905, a mandrel launcher 3910, a
mandre13915, a first fluid passage 3920, a tubular member 3925, slips 3930,
seals
3935, a shoe 3940, and a second fluid passage 3945. In a preferred embodiment,
the apparatus 3900 is used to radially expand the mandrel launcher 3910 and
tubular member 3925. In this manner, the apparatus 3900 may be used to form
a wellbore casing, line a wellbore casing, form a pipeline, line a pipeline,
form a
structural support member, or repair a wellbore casing, pipeline or structural
support member. In a preferred embodiment, the apparatus 3900 is used to clad
at least a portion of the tubular member 3925 onto a preexisting structural
member.
The support member 3905 is preferably coupled to the mandrel launcher
3910. The support member 3905 preferably comprises a tubular member
fabricated from any number of conventional commercially available materials
such
as, for example, oilf'ield country tubular goods, low alloy steel, carbon
steel, or
stainless steel. The support member 3905, the mandrel launcher 3910, the
tubular
member 3925, and the shoe 3940 are preferably selected to fit through a
preexisting section of wellbore casing 3950. In this manner, the apparatus
3900
may be positioned within the wellbore casing 3970. In a preferred embodiment,
the support member 3905 is releasably coupled to the mandrel launcher 3910. In
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this manner, the support member 3905 may be decoupled from the mandrel
launcher 3910 upon the completion of an extrusion operation.
The mandrel launcher 3910 is coupled to the support member 3905 and the
tubular member 3925. The mandrel launcher 3910 preferablv comprise a tubular
member having a variable cross-section and a reduced wall thickness in order
to
facilitate the radial expansion process. In a preferred embodiment, the cross-
sectional area of the mandrel launcher 3910 at one end is adapted to mate with
the
mandrel 3915, and at the other end, the cross-sectional area of the mandrel
launcher 3910 is adapted to match the cross-sectional area of the tubular
member
3925. In a preferred embodiment, the wall thickness of the mandrel launcher
3910
ranges from about 50 to 100 % of the wall thickness of the tubular member 3925
in order to facilitate the initiation of the radial expansion process.
The mandrel launcher 3910 may be fabricated from any number of
conventional commercially available materials such as, for example, oilfield
country tubular goods, low allow steel, stainless steel, or carbon steel. In a
preferred embodiment, the mandrel launcher 3910 is fabricated from oilfield
country tubular goods having higher strength but lower wall thickness than the
tubular member 3925 in order to optimally match the burst strength of the
tubular
member 3925. In a preferred embodiment, the mandrel launcher 3910 is
removably coupled to the tubular member 3925. In this manner, the mandrel
launcher 3910 may be removed from the wellbore 3960 upon the completion of an
extrusion operation.
The mandrel 3915 is coupled to the mandrel launcher 3910. The mandrel
3915 preferably comprise an annular member having a conic section fabricated
from any number of conventional commercially available materials such as, for
example, tool steel, carbon steel, ceramics, or composite materials. In a
preferred
embodiment, the angle of attack of the conic section of the mandrel 3915
ranges
from about 10 to 30 degrees in order to optimally expand the mandrel launcher
3910 and the tubular member 3925 in the radial direction. In a preferred
embodiment, the surface hardness of the conic section of the mandre13915
ranges
from about 58 to 62 Rockwell C in order to optimally provide high strength and
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resist wear and galling. In an alternative embodiment, the mandrel 3915 is
expandable in order to further optimally augment the radial expansion process.
The fluid passage 3920 is positioned within the mandrel 3915. The fluid
passage 3920 is preferably adapted to convey fluidic materials such as cement,
water, epoxy, lubricants, and slag mix at operating pressures and flow rates
ranging from about 0 to 9,000 psi and 0 to 3,000 gallons/minute in order to
optimally provide operational efficiency. The fluid passage 3920 preferably
includes an inlet 3965 adapted to receive a plug, or other similar device. In
this
manner, the interior chamber 3970 above the mandrel 3915 may be fluidicly
isolated from the interior chamber 3975 below the mandrel 3915.
The tubular member 3925 is coupled to the mandrel launcher 3910, the slips
3930 and the seals 3935. The tubular member 3925 preferably comprises a
tubular
member fabricated from any number of conventional commercially available
materials such as, for example, low alloy steel, carbon steel, stainless
steel, or
oilfield country tubular goods. In a preferred embodiment, the tubular member
3925 is fabricated from oilfield country tubular goods.
The slips 3930 are coupled to the outside surface of the tubular member
3925. The slips 3930 preferably are adapted to couple to the interior walls of
a
casing, pipeline or other structure upon the radial expansion of the tubular
member 3925. In this manner, the slips 3930 provide structural support for the
expanded tubular member 3925. The slips 3930 may comprise any number of
conventional commercially available slips, modified in accordance with the
teachings of the present disclosure.
The seals 3935 are coupled to the outside surface of the tubular member
3925. The seals 3935 preferably provide a fluidic seal between the outside
surface
of the expanded tubular member 3925 and the interior walls of a casing,
pipeline
or other structure upon the radial expansion of the tubular member 3925. In
this
manner, the seals 3935 provide a fluidic seal for the expanded tubular member
3925. The seals 3935 may comprise any number of conventional commercially
available seals such as, for example, lead, rubber or epoxy. In a preferred
embodiment, the seals 3935 comprise Stratalok epoxy material available from
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Halliburton Energy Services in order to optimally provide structural support
for
the typical tensile and compressive loads.
The shoe 3940 is coupled to the tubular member 3925. The shoe 3940
preferably comprises a substantially tubular member having a fluid passage
3945
for conveying fluidic materials from the chamber 3975 to the annular region
3970
outside of the apparatus 3900. The shoe 3940 may comprise any number of
conventional commercially available shoes modified in accordance with the
teachings of the present disclosure.
During operation of the apparatus 3900, the apparatus 3900 is preferably
lowered into a wellbore 3960 having a preexisting section of wellbore casing
3975.
In a preferred embodiment, the apparatus 3900 is positioned with at least a
portion of the tubular member 3925 overlapping with a portion of the wellbore
casing 3975. In this manner, the radial expansion of the tubular member 3925
will
preferably cause the outside surface of the expanded tubular member 3925 to
couple with the inside surface of the welibore casing 3975. In a preferred
embodiment, the radial expansion of the tubular member 3925 will also cause
the
slips 3930 and seals 3935 to engage with the interior surface of the wellbore
casing
3975. In this manner, the expanded tubular member 3925 is provided with
enhanced structural support by the slips 3930 and an enhanced fluid seal by
the
seals 3935.
As illustrated in FIG. 24B, after placement of the apparatus 3900 in an
overlapping relationship with the wellbore casing 3975, a fluidic material
3980 is
preferably pumped into the chamber 3970. The fluidic material 3980 then passes
through the fluid passage 3920 into the chamber 3975. The fluidic materia13980
then passes out of the chamber 3975, through the fluid passage 3945, and into
the
annular region 3970. In a preferred embodiment, the fluidic material 3980 is
pumped into the chamber 3970 at operating pressures and flow rates ranging
from
about 0 to 9,000 psi and 0 to 3,000 gallons/minute in order to optimally
provide
operational efficiency. In a preferred embodiment, the fluidic material 3980
comprises a hardenable fluidic sealing material in order to form a hardened
outer
annular member around the expanded tubular member 3925.
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As illustrated in FIG. 24C, at some later point in the process, a ball 3985,
plug or other similar device, is introduced into the pumped fluidic material
3980.
In a preferred embodiment, the bal13985 mates with and seals off the inlet
3965
of the fluid passage 3920. In this manner, the chamber 3970 is fluidicly
isolated
from the chamber 3975.
As illustrated in FIG. 24D, after placement of the ball 3985 in the inlet 3965
of the fluid passage 3920, afluidic materia13990 is pumped into the chamber
3970.
The fluidic material is preferably pumped into the chamber 3970 at operating
pressures and flow rates ranging from about 0 to 9,000 psi and 0 to 3,000
gallons/minute in order to provide optimal operating efficiency. The fluidic
material 3990 may comprise any number of conventional commercially available
materials such as, for example, water, drilling mud, cement, epoxy, or slag
mix. In
a preferred embodiment, the fluidic material 3990 comprises a non-hardenable
fluidic material in order to maximize operational efficiency.
Continued pumping of the fluidic material 3990 increases fluidic material
3980 increases the operating pressure within the chamber 3970. The increased
operating pressure in the chamber 3970 then causes the mandrel 3915 to extrude
the mandrel launcher 3910 and tubular member 3925 off of the conical face of
the
mandrel 3915. The extrusion of the mandrel launcher 3910 and tubular rnember
3925 off of the conical face of the mandre13915 causes the mandrel launcher
3910
and tubular member 3925 to expand in the radial direction. Continued pumping
of the fluidic material 3990 preferably causes the entire length of the
tubular.
member 3925 to expand in the radial direction.
In a preferred embodiment, the pumping rate and pressure of the fluidic
material 3990 is reduced during the latter stages of the extrusion process in
order
to minimize shock to the apparatus 3900. In a preferred embodiment, the
apparatus 3900 includes shock absorbers for absorbing the shock caused by the
completion of the extrusion process. In a preferred embodiment, the extrusion
process causes the mandrel 3915 to move in an axial direction 3995.
As illustrated in FIG. 24E, in a preferred embodiment, upon the completion
of the extrusion process, the support member 3905, packer 3910, first fluid
conduit
3915, annular seal 3930, second fluid conduit 3935, mandrel 3945, and mandrel
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launcher 3950 are removed from the wellbore 3980. In a preferred embodiment,
the resulting new section of wellbore casing includes the preexisting wellbore
casing 3975, the expanded tubular member 3925, the slips 3930, the seals 3935,
the
shoe 3940, and an outer annular layer 4000 of hardened fluidic material.
In an alternative embodiment, the apparatus 3900 is used to repair a
preexisting wellbore casing or pipeline. In this alternative embodiment, both
ends
of the tubular member 3955 preferably include slips 3960 and seals 3965.
In an alternative embodiment, the apparatus 3900 is used to form a tubular
structural support for a building or offshore structure.
Referring to FIGS. 25 and 26, the optimal relationship between the angle
of attack of an expansion mandrel and the m.inimally required propagation
pressure during the expansion of a tubular member will now be described. As
illustrated in FIG. 25, during the radial expansion of a tubular member 4100
by
an expansion mandre14105, the expansion mandrel 4105 is displaced in the axial
direction. The angle of attack a of the conical surface 4110 of the expansion
mandre14105 directly affects the required propagation pressure PPR necessary
to
radially expand the tubular member 4100. Referring to FIG. 26, for typical
grades
of materials and typical geometries, the propagation pressure Ppx is minimized
for
an angle of attack of approximately 25 degrees. Furthermore, the optimal range
of the angle of attack a ranges from about 10 to 30 degrees in order to
minimize
the range of required minimum propagation pressure PpR-
Referring to FIG. 27, an embodiment of an expandable threaded connection
4300 will now be described. The expandable threaded connection 4300 preferably
includes a first tubular member 4305, a second tubular member 4310, a threaded
connection 4315, an 0-ring groove 4320, and an 0-ring 4325.
The first tubular member 4305 includes an inside wall 4330 and an outside
wall 4335. The first tubular member 4305 preferably compi-ises an annular
member having a substantially constant wall thickness. The second tubular
member 4310 includes an inside wall 4340 and an outside wall 4345. The second
tubular member 4310 preferably comprises an annular member having a
substantially constant wall thickness.
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The first and second tubular members, 4305 and 4310, may comprise any
number of conventional commercially available members. In a preferred
embodiment, the inside and outside diameters of the first and second tubular
members, 4305 and 4310, are substantially equal. In this manner, the burst
strength of the tubular members, 4305 and 4310, are substantially equaL This
minimizes the possibility of a catastrophic failure during the radial
expansion
process.
The threaded connection 4315 may comprise any number of conventional
threaded connections suitable for use with tubular members. In a preferred
embodiment, the threaded connection 4315 comprises a pin-and-box threaded
connection. In this manner, the assembly of the first tubular member 4305 to
the
second tubular member 4310 is optimized.
The 0-ring groove 4320 is preferably provided in the threaded portion of the
interior wall 4340 of the second tubular member 4310. The 0-ring groove 4320
is
preferably adapted to receive and support one or more 0-rings. The volumetric
size of the 0-ring groove 4320 is preferably selected to permit the 0-ring
4325 to
expand at least approximately 20% in the axial direction during the radial
expansion process. In this manner, deformation of the outer surface 4345 of
the
second tubular member 4310 during and upon the completion of the radial
expansion process is minimized_
The 0-ring 4325 is supported by the 0-ring groove 4320. The 0-ring 4325
optimally ensures that a fluid-tight seal is maintained between the first
tubular
member 4305 and the second tubular member 4310 throughout and upon the
completion of the radial expansion process.
Referring to FIG. 28, an alternative embodiment of an expandable threaded
connection 4500 will now be described. The expandable threaded connection 4500
includes a first tubular member 4505, a second tubular member 4510, a threaded
connection 4515, an 0-ring groove 4520, and an 0-ring 4525.
The first tubular member 4505 includes an inside wall 4530 and an outside
wall 4535. The first tubular member 4305 preferably comprises an annular
member having a substantially constant wall thickness. The second tubular
member 4510 includes an inside wall 4540 and an outside wall 4545. The second
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tubular member 4510 preferably comprises an annular member having a
substantially constant wall thickness.
The first and second tubular members, 4505 and 4510, may comprise any
number of conventional commercially available members. In a preferred
embodiment, the inside and outside diameters of the first and second tubular
members, 4505 and 4510, are substantially equal. In this manner, the burst
strength of the tubular members, 4505 and 4510, are substantially equal. This
minimizes the possibility of a catastrophic failure during the radial
expansion
process.
The threaded connection 4515 may comprise any number of conventional
threaded connections suitable for use with tubular members. In a preferred
embodiment, the threaded connection 4515 comprises a pin-and-box threaded
connection. In this manner, the assembly of the first tubular member 4505 to
the
second tubular member 4510 is optimized.
The 0-ring groove 4520 is preferably provided in the threaded portion of the
interior wall 4540 of the second tubular member 4510 immediately adjacent to
an
end portion of the threaded connection 4515. In this manner, the sealing
effect
provided by the 0-ring 4525 is optimized. The 0-ring groove 4520 is preferably
adapted to receive and support one or more 0-rings. The volumetric size of the
0-
ring groove 4520 is preferably selected to permit the 0-ring 4525 to expand at
least
approximately 20% in the axial direction during the radial expansion process.
In
this manner, deformation of the outer surface 4545 of the second tubular
member
4510 during and upon the completion of the radial expansion process is
minimized.
The 0-ring 4525 is supported by the 0-ring groove 4520. The 0-ring 4525
optimally ensures that a fluid-tight seal is maintained between the first
tubular
member 4505 and the second tubular member 4510 throughout and upon the
completion of the radial expansion process.
Referring to FIG. 29, an alternative embodiment of an expandable threaded
connection 4700 will now be described. The expandable threaded connection 4700
includes a first tubular member 4705, a second tubular member 4710, a threaded
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connection 4715, an 0-ring groove 4720, a first 0-ring 4725, and a second 0-
ring
4730.
The first tubular member 4705 includes an inside wall 4735 and an outside
wall 4740. The first tubular member 4705 preferably comprises an annular
member having a substantially constant wall thickness. The second tubular
member 4710 includes an inside wall 4745 and an outside wall 4750. The second
tubular member 4710 preferably comprises an annular member having a
substantially constant wall thickness.
The first and second tubular members, 4705 and 4710, may comprise any
number of conventional commercially available members. In a preferred
embodiment, the inside and outside diameters of the first and second tubular
members, 4705 and 4710, are substantially equal. In this manner, the burst
strength of the tubular members, 4705 and 4710, are substantially equal. This
minimizes the possibility of a catastrophic failure during the radial
expansion
process.
The threaded connection 4715 may comprise any number of conventional
threaded connections suitable for use with tubular members. In a preferred
embodiment, the threaded connection 4715 comprises a pin-and-box threaded
connection. In this manner, the assembly of the first tubular member 4705 to
the
second tubular member 4710 is optimized.
The 0-ring groove 4720 is preferably provided in the threaded portion of the
interior wall 4745 of the second tubular member 4710 immediately adjacent to
an
end portion of the threaded connection 4715. In this manner, the sealing
effect
provided by the 0-rings, 4725 and 4730, is optimized. The 0-ring groove 4720
is
preferably adapted to receive and support a plurality of 0-rings. The
volumetric
size of the 0-ring groove 4720 is preferably selected to permit the 0-rings,
4725
and 4730, to expand at least approximately 20% in the axial direction during
the
radial expansion process. In this manner, deformation of the outer surface
4750
of the second tubular member 4710 during and upon the completion of the radial
expansion process is minimized.
The 0-rings, 4725 and 4730, are supported by the 0-ring groove 4720. The
pair of 0-rings, 4725 and 4730, optimally ensure that a fluid-tight seal is
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maintained between the first tubular member 4705 and the second tubular
member 4710 throughout and upon the completion of the radial expansion
process_
In particular, the use of a pair of adjacent 0-rings provides redundancy in
the seal
between the first tubular member 4705 and the second tubular member 4710.
Referring to FIG. 30, an alternative embodiment of an expandable threaded
connection 4900 will now be described. The expandable threaded connection 4900
includes a first tubular member 4905, a second tubular member 4910, a threaded
connection 4915, a first 0-ring groove 4920, a second 0-ring grove 4925, a
first 0-
ring 4930, and a second 0-ring 4935.
The first tubular member 4905 includes an inside wall 4940 and an outside
wall 4945. The first tubular member 4905 preferably comprises an annular
member having a substantially constant wall thickness_ The second tubular
member 4910 includes an inside wall 4950 and an outside wall 4955. The second
tubular member 4910 preferably comprises an annular member having a
substantially constant wall thickness.
The first and second tubular members, 4905 and 4910, may comprise any
number of conventional commercially available tubular members. In a preferred
embodiment, the inside and outside diameters of the first and second tubular
members, 4905 and 4910, are substantially equal. In this manner, the burst
strength of the tubular members, 4905 and 4910, are substantially equal. This
minimizes the possibility of a catastrophic failure during the radial
expansion
process.
The threaded connection 4915 may comprise any number of conventional
threaded connections suitable for use with tubular members. In a preferred
embodiment, the threaded connection 4915 comprises a pin-and-box threaded
connection. In this manner, the assembly of the first tubular member 4905 to
the
second tubular member 4910 is optimized.
The first 0-ring groove 4920 is preferably provided in the threaded portion
of the interior wall 4950 of the second tubular member 4910 that is separated
from
an end portion of the threaded connection 4915. In this manner, the seating
effect
provided by the 0-rings, 4930 and 4935, is optimized. The first 0-ring groove
4920 is preferably adapted to receive and support one more 0-rings. The
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volumetric size of the hrst 0-ring groove 4920 is preferably selected to
permit the
0-ring 4930 to expand at least approximately 20% in the axial direction during
the
radial expansion process. In this manner, deformation of the outer surface
4955
of the second tubular member 4910 during and upon the completion of the radial
expansion process is minimized.
The second 0-ring groove 4925 is preferably provided in the threaded
portion of the interior wa11 4950 of the second tubular member 4910 that is
immediately adjacent to an end portion of the threaded connection 4915. In
this
manner, the sealing effect provided by the 0-rings, 4930 and 4935, is
optimized.
The second 0-ring groove 4925 is preferably adapted to receive and support one
more 0-rings. The volumetric size of the second 0-ring groove 4925 is
preferably
selected to permit the 0-ring 4935 to expand at least approximately 20% in the
axial direction during the radial expansion process. In this manner,
deformation
of the outer surface 4955 of the second tubular member 4910 during and upon
the
completion of the radial expansion process is minimized.
The 0-rings, 4930 and 4935, are supported by the 0-ring grooves, 4920 and
4925. The use of a pair of 0-rings, 4930 and 4935, that are axially separated
optimally ensures that a fluid-tight seal is maintained between the first
tubular
member 4905 and the second tubular member 4910 tiiroughout and upon the
completion of the radial expansion process. In particular, the use of a pair
of 0-
rings provides redundancy in the seal between the first tubular member 4905
and
the second tubular member 4910.
In a preferred embodiment, the expandable threaded connections 4300,
4500, 4700, and/or 4900 are used in combination with one or more of the
embodiments illustrated in FIGS. 1-24E in order to optimally expand a
plurality
of tubular members coupled end to end using the expandable threaded
connections
4300, 4500, 4700 and/or 4900.
Referring to FIG. 31, the lubrication of the interface between an expansion
mandrel and a tubular member during the radial expansion process will now be
described. As illustrated in FIG. 31, during the radial expansion process, an
expansion cone 5000 radially expands a tubular member 5005 by moving in an
axial direction 5010 relative to the tubular member 5005. The interface
between
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the outer surface 5010 of the tapered portion 5015 of the expansion cone 5000
and
the inner surface 5020 of the tubularmember 5005 includes a leading edge
portion
5025 and a trailing edge portion 5030.
During the radial expansion process, the leading edge portion 5025 is
preferably lubricated by the presence of lubricating fluids provided ahead of
the
expansion cone 5000. However, because the radial clearance between the
expansion cone 5000 and the tubular member 5005 in the trailing edge portion
5030 during the radial expansion process is typically extremely small, and the
operating contact pressures between the tubular member 5005 and the expansion
mandre15000 are extremely high, the quantity of lubricating fluid provided to
the
trailing edge portion 5030 is typically greatly reduced. In typical radial
expansion
operations, this reduction in lubrication in the trailing edge portion 5030
increases
the forces required to radially expand the tubular member 5005.
Referring to FIG. 32, an embodiment of a system for lubricating the
interface between an expansion cone and a tubular member during the expansion
process wiIl now be described. As illustrated in FIG. 32, an expansion cone
5100,
having a front end 5100a and a rear end 5100b, includes a tapered portion 5105
having an outer surface 3110, one or more circumferential grooves 5115a and
5115b, and one more internal flow passages 5120a and 5120b.
In a preferred embodiment, the circumferential grooves 5115 are fluidicly
coupled to the internal flow passages 5120. In this manner, during the radial
expansion process, lubricating fluids are transmitted from the area ahead of
the
front 5100a of the expansion cone 5100 into the circumferential grooves 5115.
Thus, the trailing edge portion of the interface between the expansion cone
5100
and a tubular member is provided with an increased supply of lubricant,
thereby
reducing the amount of force required to radially expand the tubular member.
In
a preferred embodiment, the lubricating fluids are injected into the internal
flow
passages 5120 using a fluid conduit that is coupled to the tapered end 5105 of
the
expansion cone 5100. Alternatively, lubricating fluids are provided for the
internal
flow passages 5120 using a supply of lubricating fluids provided adjacent to
the
front 5100a of the expansion cone 5100.
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In a preferred embodiment, the expansion cone 5100 includes a plurality of
circumferential grooves 5115. In a preferred embodiment, the cross sectional
area
of the circumferential grooves 5115 range from about 2X10' ini to 5X10-Z in2
in
order to optimally provide lubrication to the trailing edge portion of the
interface
between the expansion cone 5100 and a tubular member during the radial
expansion process. In a preferred embodiment, the expansion cone 5100 includes
circumferential grooves 5115 concentrated about the axial midpoint of the
tapered
portion 5105 in order to optimally provide lubrication to the trailing edge
portion
of the interface between the expansion cone 5100 and a tubular member during
the radial expansion process. In a preferred embodiment, the circumferential
grooves 5115 are equally spaced along the trailing edge portion of the
expansion
cone 5100 in order to optimally provide lubrication to the trailing edge
portion of
the interface between the expansion cone 5100 and a tubular member during the
radial expansion process.
In a preferred embodiment, the expansion cone 5100 includes a plurality of
flow passages 5120 coupled to each of the circumferential grooves 5115. In a
preferred embodiment, the cross-sectional area of the flow passages 5120
ranges
from about 2X10" inZ to 5X10'2 in2 in order to optimally provide lubrication
to the
trailing edge portion of the interface between the expansion cone 5100 and a
tubular member during the radial expansion process. In a preferred embodiment,
the cross sectional area of the circumferential grooves 5115 is greater than
the
cross sectional area of the flow passage 5120 in order to minimize resistance
to
fluid flow.
Referring to FIG. 33, another embodiment of a system for lubricating the
interface between an expansion cone and a tubular member during the expansion
process will now be described. As illustrated in FIG. 33, an expansion cone
5200,
having a front end 5200a and a rear end 5200b, includes a tapered portion 5205
having an outer surface 5210, one or more circumferential grooves 5215a and
5215b, and one or more axial grooves 5220a and 5220b.
In a preferred embodiment, the circumferential grooves 5215 are fluidicly
coupled to the axial groves 5220. In this manner, during the radial expansion
process, lubricating fluids are transmitted from the area ahead of the front
5200a
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of the expansion cone 5200 into the circumferential grooves 5215. Thus, the
trailing edge portion of the interface between the expansion cone 5200 and a
tubular member is provided with an increased supply of lubricant, thereby
reducing the amount of force required to radially expand the tubular member.
In
a preferred embodiment, the axial grooves 5220 are provided with lubricating
fluid
using a supply of lubricating fluid positioned proximate the front end 5200a
of the
expansion cone 5200. In a preferred embodiment, the circumferential grooves
3215 are concentrated about the axial midpoint of the tapered portion 5205 of
the
expansion cone 5200 in order to optimally provide lubrication to the trailing
edge
portion of the interface between the expansion cone 5200 and a tubular member
during the radial expansion process. In a preferred embodiment, the
circumferential grooves 5215 are equally spaced along the trailing edge
portion of
the expansion cone 5200 in order to optimally provide lubrication to the
trailing
edge portion of the interface between the expansion cone 5200 and a tubular
member during the radial expansion process.
In a preferred embodiment, the expansion cone 5200 includes a plurality of
circumferential grooves 5215. In a preferred embodiment, the cross sectional
area
of the circumferential grooves 5215 range from about 2X10-4 in2 to 5X10"2 in'
in
order to optimally provide lubrication to the trailing edge portion of the
interface
between the expansion cone 5200 and a tubular member during the radial
expansion process.
In a preferred embodiment, the expansion cone 5200 includes a plurality of
axial grooves 5220 coupled to each of the circumferential grooves 5215. In a
preferred embodiment, the cross sectional area of the axial grooves 5220
ranges
from about 2X10-' inz to 5X10'2 in' in order to optimally provide lubrication
to the
trailing edge portion of the interface between the expansion cone 5200 and a
tubular member during the radial expansion process. In a preferred embodiment,
the cross sectional area of the circumferential grooves 5215 is greater than
the
cross sectional area of the axial grooves 5220 in order to minimize resistance
to
fluid flow. In a preferred embodiment, the axial groves 5220 are spaced apart
in
the circumferential direction by at least about 3 inches in order to optimally
provide lubrication during the radial expansion process.
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Referring to FIG. 34, another embodiment of a system for lubricating the
interface between an expansion cone and a tubular member during the expansion
process will now be described. As illustrated in FIG. 34, an expansion cone
5300,
having a front end 5300a and a rear end 5300b, includes a tapered portion 5305
having an outer surface 5310, one or more circumferential grooves 5315a and
5315b, and one or more internal flow passages 5320a and 5320b.
In a preferred embodiment, the circumferential grooves 5315 are fluidicly
coupled to the internal flow passages 5320. In this manner, during the radial
expansion process, lubricating fluids are transmitted from the areas in front
of the
front 5300a and/or behind the rear 5300b of the expansion cone 5300 into the
circumferential grooves 5315. Thus, the trailing edge portion of the interface
between the expansion cone 5300 and a tubular member is provided with an
increased supply of lubricant, thereby reducing the amount of force required
to
radially expand the tubular member. Furthermore, the lubricating fluids also
preferably pass to the area in front of the expansion cone. In this manner,
the area
adjacent to the front 5300a of the expansion cone 5300 is cleaned of foreign
materials. In a preferred embodiment, the lubricating fluids are injected into
the
internal flow passages 5320 by pressurizing the area behind the rear 5300b of
the
expansion cone 5300 during the radial expansion process. .
In a preferred embodiment, the expansion cone 5300 includes a plurality of
circumferential grooves 5315. In a preferred embodiment, the cross sectional
area
of the circumferential grooves 5315 ranges from about 2X10'4 in2 to 5X10"2 in?
respectively, in order to optimally provide lubrication to the trailing edge
portion
of the interface between the expansion cone 5300 and a tubular member during
the radial expansion process. In a preferred embodiment, the expansion cone
5300
includes circumferential grooves 5315 that are concentrated about the axial
midpoint of the tapered portion 5305 in order to optimally provide lubrication
to
the trailing edge portion of the interface between the expansion cone 5300 and
a
tubular member during the radial expansion process. In a preferred embodiment,
the circumferential grooves 5315 are equally spa:ced along the trailing edge
portion
of the expansion cone 5300 in order to optimally provide lubrication to the
trailing
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edge portion of the interface between the expansion cone 5300 and a tubular
member during the radial expansion process.
In a preferred embodiment, the expansion cone 5300 includes a plurality of
flow passages 5320 coupled to each of the circumferential grooves 5315. In a
preferred embodiment, the flow passages 5320 fluidicly couple the front end
5300a
and the rear end 5300b of the expansion cone 5300. In a preferred embodiment,
the cross-sectional area of the flow passages 5320 ranges from about 2X10-0
in2 to
5X10'2 in2 in order to optimally provide lubrication to the trailing edge
portion of
the interface between the expansion cone 5300 and a tubular member during the
radial expansion process. In a preferred embodiment, the cross sectional area
of
the circumferential grooves 5315 is greater than the cross-sectional area of
the
flow passages 5320 in order to minimize resistance to fluid flow.
Referring to FIG. 35, an embodiment of a system for lubricating the
interface between an expansion cone and a tubular member during the expansion
process will now be described. As illustrated in FIG. 35, an expansion cone
5400,
having a front end 5400a and a rear end 5400b, includes a tapered portion 5405
having an outer surface 5410, one or more circumferential grooves 5415a and
5415b, and one or more axial grooves 5420a and 5420b.
In a preferred embodiment, the circumferential grooves 5415 are fluidicly
coupled to the axial grooves 5420. In this manner, during the radial expansion
process, lubricating fluids are transmitted from the areas in front of the
front
5400a and/or behind the rear 5400b of the expansion cone 5400 into the
circumferential grooves 5415. Thus, the trailing edge portion of the interface
between the expansion cone 5400 and a tubular member is provided with an
increased supply of lubricant, thereby reducing the amount of force required
to
radially expand the tubular member. Furthermore, in a preferred embodiment,
pressurized lubricating fluids pass from the fluid passages 5420 to the area
in front
of the front 5400a of the expansion cone 5400. In this manner, the area
adjacent
to the front 5400a of the expansion cone 5400 is cleaned of foreign materials.
In
a preferred embodiment, the lubricating fluids are injected into the internal
flow
passages 5420 by pressurizing the areabehind the rear 5400b expansion cone
5400
during the radial expansion process.
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In a preferred embodiment, the expansion cone 5400 includes a plurality of
circumferential grooves 5415. In a preferred embodiment, the cross sectional
area
of the circumferential grooves 5415 range from about 2X10-4 in2 to 5X10-2 in2
in
order to opti.mally provide lubrication to the trailing edge portion of the
interface
between the expansion cone 5400 and a tubular member during the radial
expansion process. In a preferred embodiment, the expansion cone 5400 includes
circumferential grooves 5415 that are concentrated about the axial midpoint of
the
tapered portion 5405 in order to optimally provide lubrication to the
traili_ng edge
portion of the interface between the expa.nsion cone 5400 and a tubular member
during the radial expansion process. In a preferred embodiment, the
circumferential groove9 5415 are equally spaced along the trailing edge
portion of
the expansion cone 5400 in order to optimally provide lubrication to the
trailing
edge portion of the interface between the expansion cone 5400 and a tubular
member during the radial expansion process.
In a preferred embodiment, the expansion cone 5400 includes a plurality of
axial grooves 5420 coupled to each of the circumferential grooves 5415. In a
preferred embodiment, the axial grooves 5420 fluidicly couple the front end
and
the rear end of the expansion cone 5400. In a preferred embodiment, the cross
sectional area of the axial grooves 5420 range from about 2X10'' in2 to 5X10'2
in2,
respectively, in order to optimally provide lubrication to the trailing edge
portion
of the interface between the expansion cone 5400 and a tubular member during
the radial expansion process. In a preferred embodiment, the cross sectional
area
of the circumferential grooves 5415 is greater than the cross sectional area
of the
axial grooves 5420 in order to minimize resistance to fluid flow. In a
preferred
embodiment, the axial grooves 5420 are spaced apart in the circumferential
direction by at least about 3 inches in order to optimally provide lubrication
during
the radial expansion process.
Referring to FIG. 36, another embodiment of a system for lubricating the
interface between an expansion cone and a tubular member during the expansion
process will now be described. As illustrated in FIG. 36, an expansion cone
5500,
having a front end 5500a and a rear end 5500b, in0ludes a tapered portion 5505
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having an outer surface 5510, one or more circumferential grooves 5515a and
5515b, and one or more axial grooves 5520a and 5520b.
In a preferred embodiment, the circumferential grooves 5515 are fluidiclv
coupled to the axial grooves 5520. In this manner, during the radial expansion
process, lubricating fluids are transmitted from the area ahead of the front
5500a
of the expansion cone 5500 into the circumferential grooves 5515. Thus, the
trailing edge portion of the interface between the expansion cone 5500 and a
tubular member is provided with an increased supply of lubricant, thereby
reducing the amount of force required to radially expand the tubular member.
In
a preferred embodiment, the lubricating fluids are injected into the axial
grooves
5520 using a fluid conduit that is coupled to the tapered end 3205 of the
expansion
cone 3200.
In a preferred embodiment, the expansion cone 5500 includes a plurality of
circumferential grooves 5515. In a preferred embodiment, the cross sectional
area
of the circumferential grooves 5515 ranges from about 2X10-4 in2 to 5X10"2 in2
in
order to optimally provide lubrication to the trailing edge portion of the
interface
between the expansion cone 5500 and a tubular member during the radial
expansion process. In a preferred embodiment, the expansion cone 5500 includes
circumferential grooves 5515 that are concentrated about the axial midpoint of
the
tapered portion 5505 in order to optimally provide lubrication to the trailing
edge
portion of the interface between the expansion cone 5500 and a tubular member
during the radial expansion process. In a preferred embodiment, the
circumferential grooves 5515 are equally spaced along the trailing edge
portion of
the expansion cone 5500 in order to optimally provide lubrication to the
trailing
edge portion of the interface between the expansion cone 5500 and a tubular
member during the radial expansion process.
In a preferred embodiment, the expansion cone 5500 includes a plurality of
axial grooves 5520 coupled to each of the circumferential grooves 5515. In a
preferred embodiment, the axial grooves 5520 intersect each of the
circumferential
groves 5515 at an acute angle. In a preferred embodiment, the cross sectional
area
of the axial grooves 5520 ranges from about 2X10-4 inl to 5X10-2 in2 in order
to
optimally provide lubrication to the trailing edge portion of the interface
between
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the expansion cone 5500 and a tubular member during the radial expansion
process. In a preferred embodiment, the cross sectional area of the
circumferential
grooves 5515 is greater than the cross sectional area of the axial grooves
5520. In
a preferred embodiment, the axial grooves 5520 are spaced apart in the
circumferential direction by at least about 3 inches in order to optimally
provide
lubrication during the radial expansion process. In a preferred embodiment,
the
axial grooves 5520 intersect the longitudinal axis of the. expansion cone 5500
at a
larger angle than the angle of attack of the tapered portion 5505 in order to
optimally provide lubrication during the radial expansion process.
Referring to FIG. 37, another embodiment of a system for lubricating the
interface between an expansion cone and a tubular member during the expansion
process will now be described. As illustrated in FIG. 37, an expansion cone
5600,
having a front end 5600a and a rear end 5600b, includes a tapered portion 5605
having an outer surface 5610, a spiral circumferential groove 5615, and one or
more internal flow passages 5620.
In a preferred embodiment, the circumferential groove 5615 is fluidicly
coupled to the internal flow passage 5620. In this manner, during the radial
expansion process, lubricating fluids are transmitted from the area ahead of
the
front 5600a of the expansion cone 5600 into the circumferential groove 5615.
Thus, the trailing edge portion of the interface between the expansion cone
5600
and a tubular member is provided with an increased supply of lubricant,
thereby
reducing the amount of force required to radially expand the tubular member.
In
a preferred embodiment, the lubricating fluids are injected into the internal
flow
passage 5620 using a fluid conduit that is coupled to the tapered end 5605 of
the
expansion cone 5600.
In a preferred embodiment, the expansion cone 5600 includes a plurality of
spiral circumferential grooves 5615. In a preferred embodiment, the cross
sectional area of the circumferential groove 5615 ranges from about 2X10' in2
to
5X10-2 in2 in order to optimally provide lubrication to the trailing edge
portion of
the interface between the expansion cone 5600 and a tubular member during the
radial expansion process. In a preferred embodiment, the expansion cone 5600
includes circumferential grooves 5615 that are concentrated about the axial
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midpoint of the tapered portion 5605 in order to optimally provide lubrication
to
the trailing edge portion of the interface between the expansion cone 5600 and
a
tubular member during the radial expansion process. In a preferred embodiment,
the circumferential grooves 5615 are equally spaced along the trailing edge
portion
of the expansion cone 5600 in order to optimally provide lubrication to the
trailing
edge portion of the interface between the expansion cone 5600 and a tubular
member during the radial, expansion process.
In a preferred embodiment, the expansion cone 5600 includes a plurality of
flow passages 5620 coupled to each of the circumferential grooves 5615. In a
preferred embodiment, the cross-sectional area of the flow passages 5620
ranges
from about 2X10 in2 to 5X10,2 in2 in order to optimally provide lubrication
to the
trailing edge portion of the interface between the expansion cone 5600 and a
tubular member during the radial expansion process. In a preferred embodiment,
the cross sectional area of the circumferential groove 5615 is greater than
the cross
sectional area of the flow passage 5620 in order to minimize resistance to
fluid
flow.
Referring to FIG. 38, another embodiment of a system for lubricating the
interface between an expansion cone and a tubular member during the expansion
process will now be described. As illustrated in FIG. 38, an expansion cone
5700,
having a front end 5700a and a rear end 5700b, includes a tapered portion 5705
having an outer surface 5710, a spiral circumferential groove 5715, and one or
more axial grooves 5720a, 5720b and 5720c.
In a preferred embodiment, the circumferential groove 5715 is fluidiely
coupled to the axial grooves 5720. In this manner, during the radial expansion
process, lubricating fluids are transmitted from the area ahead of the front
5700a
of the expansion cone 5700 into the circumferential groove 5715. Thus, the
trailing edge portion of the interface between the expansion cone 5700 and a
tubular member is provided with an increased supply of lubricant, thereby
reducing the amount of force required to radially expand the tubular member.
In
a preferred embodiment, the lubricating fluids are injected into the axial
grooves
5720 using a fluid conduit that is coupled to-the tapered end 5705 of the
expansion
cone 5700.
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In a preferred embodiment, the expansion cone 5700 includes a plurality of
spiral circumferential grooves 5715. In a preferred embodiment, the cross
sectional area of the circumferential grooves 5715 range from about 2X10' in2
to
5X10-Z in2 in order to optimally provide lubrication to the trailing edge
portion of
the interface between the expansion cone 5700 and a tubular member during the
radial expansion process. In a preferred embodiment, the expansion cone 5700
includes circumferential grooves 5715 concentrated about the axial midpoint of
the
tapered portion 5705 in order to optimally provide lubrication to the trailing
edge
portion of the interface between the expansion cone 5700 and a tubular member
during the radial expansion process. In a preferred embodiment, the
circumferential grooves 5715 are equally spaced along the trailing edge
portion of
the expansion cone 5700 in order to optimally provide lubrication to the
trailing
edge portion of the interface between the expansion cone 5700 and a tubular
member during the radial expansion process.
In a preferred embodiment, the expansion cone 5700 includes a plurality of
axial grooves 5720 coupled to each of the circumferential grooves 5715. In a
preferred embodiment, the cross sectional area of the axial grooves 5720 range
from about 2X10-4 inz to 5X10-2 in2 in order to optimaUy provide lubrication
to the
trailing edge portion of the interface between the expansion cone 5700 and a
tubular member during the radial expansion process. In a preferred embodiment,
the axial grooves 5720 intersect the circumferential grooves 5715 in a
perpendicular manner. In a preferred embodiment, the cross sectional area of
the
circumferential groove 5715 is greater than the cross sectional area of the
axial
grooves 5720 in order to minimize resistance to fluid flow. In a preferred
embodiment, the circumferential spacing of the axial grooves is greater than
about
3 inches in order to optimally provide lubrication during the radial expansion
process. In a preferred embodiment, the axial grooves 5720 intersect the
longitudinal axis of the expansion cone at an angle greater than the angle of
attack
of the tapered portion 5705 in order to optimally provide lubrication during
the
radial expansion process.
Referring to FIG. 39, a preferred embodiment of a system for lubricating the
interface between an expansion cone and a tubular member during the expansion
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process will now be described_ As illustrated in FIG. 39, an expansion cone
5800,
having a front end 5800a and a rear end 5800b, includes a tapered portion 5805
having an outer surface 5810, a circumferential groove 5815, a first axial
groove
5820, and one or more second axial grooves 5825a, 5825b, 5825c and 5825d_
In a preferred embodiment, the circumferential groove 5815 is fluidicly
coupled to the axial grooves 5820 and 5825. In this manner, during the radial
expansion process, lubricating fluids are preferably transmitted from the area
behind the back 5800b of the expansion cone 5800 into the circumferential
groove
5815. Thus, the trailing edge portion of the interface between the expansion
cone
5800 and a tubular member is provided with an increased supply of lubricant,
thereby reducing the amount of force required to radially expand the tubular
member. In a preferred embodiment, the lubricating fluids are injected into
the
first axial groove 5820 by pressurizing the region behind the back 5800b of
the
expansion cone 5800. In a preferred embodiment, the lubricant is further
transmitted into the second axial grooves 5825 where the lubricant preferably
cleans foreign materials from the tapered portion 5805 of the expansion cone
5800.
In a preferred embodiment, the expansion cone 5800 includes a plurality of
circumferential grooves 5815. In a preferred embodiment, the cross sectional
area
of the circumferential groove 5815 ranges from about 2X10" in2 to 5X10-2 in 2
in
order to optimally provide lubrication to the trailing edge portion of the
interface
between the expansion cone 5800 and a tubular member during the radial
expansion process. In a preferred embodiment, the expansion cone 5800 includes
circumferential grooves 5815 concentrated about the axial midpoint of the
tapered
portion 5805 in order to optimally provide lubrication to the trailing edge
portion
of the interface between the expansion cone 5800 and a tubular member during
the radial expansion process. In a preferred embodiment, the circumferential
grooves 5815 are equally spaced along the trailing edge portion of the
expansion
cone 5800 in order to optimally provide lubrication to the trailing edge
portion of
the interface between the expansion cone 5800 and a tubular member during the
radial expansion process.
In a preferred embodiment, the expansion cone 5800 includes a plurality of
first axial grooves 5820 coupled to each of the circumferential grooves 5815.
In a
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WO 01104535 PCTIUS00/18635
preferred embodiment, the first axial grooves 5820 extend from the back 5800b
of
the expansion cone 5800 and intersect the circumferential groove 5815. In a
preferred embodiment, the cross sectional area of the first axial groove 5820
ranges
from about 2X10' in2 to 5X10-2 in2 in order to optimally provide lubrication
to the
trailing edge portion of the interface between the expansion cone 5800 and a
tubular member during the radial expansion process. In a preferred embodiment,
the first axial groove 5820 intersects the circumferential groove 5815 in a
perpendicular manner. In a preferred embodiment, the cross sectional area of
the
circumferential groove 5815 is greater than the cross sectional area of the
first
axial groove 5820 in order to minimize resistance to fluid flow. In a
preferred
embodiment, the circumferential spacing of the first axial grooves 5820 is
greater
than about 3 inches in order to optimally provide lubrication during the
radial
expansion process.
In a preferred embodiment, the expansion cone 5800 includes a plurality of
second axial grooves 5825 coupled to each of the circumferential grooves 5815.
In
a preferred embodiment, the second axial grooves 5825 extend from the front
5800a of the expansion cone 5800 and intersect the circumferential groove
5815.
In a preferred embodiment, the cross sectional area of the second axial
grooves
5825 ranges from about 2X10"4 in2 to 5X10-2 in2 in order to optimally provide
lubrication to the traili.ng edge portion of the interface between the
expansion cone
5800 and a tubular member during the radial expansion process. In a preferred
embodiment, the second axial grooves 5825 intersect the circumferential groove
5815 in a perpendicular manner. In a preferred embodiment, the cross sectional
area of the circumferential groove 5815 is greater than the cross sectional
area of
the second axial grooves 5825 in order to minimize resistance to fluid flow.
In a
preferred embodiment, the circumferential spacing of the second axial grooves
5825 is greater than about 3 inches in order to optimally provide lubrication
during the radial expansion process. In a preferred embodiment, the second
axial
grooves 5825 intersect the longitudinal axis of the expansion cone 5800 at an
angle
greater than the angle of attack of the tapered portion 5805 in order to
optimally
provide lubrication during the radial expansion process.
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WO 01104535 PCT/L'=S00118635
Referring to Fig. 40, in a preferred embodiment, the first axial groove 5820
includes a first portion 5905 having a first radius of curvature 5910, a
second
portion 5915 having a second radius of curvature 5920, and a third portion
5925
having a third radius of curvature 5930. In a preferred embodiment, the radius
of
curvatures, 5910, 5920 and 5930 are substantially equal. In an exemplary
embodiment, the radius of curvatures, 5910, 5920 and 5930 are all
substantially
equal to 0_0625 inches.
Referring to Fig. 41, in a preferred embodiment, the circumferential groove
5815 includes a first portion 6005 having a first radius of curvature 6010, a
second
portion 6015 having a second radius of curvature 6020, and a third portion
6025
having a third radius of curvature 6030. In a preferred embodiment, the radius
of
curvatures, 6010, 6020 and 6030 are substantially equal. In an exemplary
embodiment, the radius of curvatures, 6010, 6020 and 6030 are all
substantially
equal to 0.125 inches.
Referring to Fig. 42, in a preferred embodiment, the second axial groove
5825 includes a first portion 6105 having a first radius of curvature 6110, a
second
portion 6115 having a second radius of curvature 6120, and a third portion
6125
having a third radius of curvature 6130. In a preferred embodiment, the first
radius of curvature 6110 is greater than the third radius of curvature 6130.
In an
exemplary embodiment, the first radius of curvature 6110 is equal to 0_5
inches,
the second radius of curvature 6120 is equal to 0.0625 inches, and the third
radius
of curvature 6130 is equal to 0.125 inches.
Referring to Fig. 43, an embodiment of an expansion mandre16200 includes
an internal flow passage 6205 having an insert 6210 including a flow paesage
6215.
In a preferred embodiment, the cross sectional area of the flow passage 6215
is less
than the cross sectional area of the flow passage 6215. More generally, in a
preferred embodiment, aplurality of inserts 6210 are provided, each with
different
sizes of flow passages 6215. In this manner, the flow passage 6215 is machined
to
a standard size, and the lubricant supply is varied by using different sized
inserts
6210. In a preferred embodiment, the teachings of the expansion mandrel 6200
are incorporated into the expansion mandrels 5100, 5300, and 5600.
248
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WO 01/04535 PCT/[JS00/18635
Referring to Fig. 44, in a preferred embodiment, the insert 6210 includes a
filter 6305 for filtering particles and other foreign materiaLs from the
lubricant
that passes into the flow passage 6205. In this manner, the foreign materials
are
prevented from clogging the flow passage 6205 and other flow passages within
the
expansion mandrel 6200.
In a preferred embodiment, the one or more of the lubrication systems and
elements of the mandrels' 5100, 5200, 5300, 5400, 5500, 5600, 5700, 5800
and/or
5900 are incorporated into the methods and apparatus for expanding tubular
members described above with reference to FIGS. 1-30. In this manner, the
amount of.force required to radially expand a tubular member in the formation
and/or repair of a wellbore casing, pipeline, or structural support is
significantly
reduced. Furthermore, the increased lubrication provided to the trail edge
portion
of the mandrel greatly reduces the amount of galling or seizure caused by the
interface between the mandrel and the tubular member during the radial
expansion process thereby permitting larger continuous sections of tubulars to
be
radially expanded in a single continuous operation. Thus, use of the mandrels
5100, 5200, 5300, 5400, 5500, 5600, 5700, 5800 and/or 5900 reduces the
operating
pressures required for radial expansion and thereby reduces the sizes of the
required hydraulic pumps and related equipment. In addition, failure,
bursting,
and/or buckling of tubular members during the radial expansion process is
significantly reduced, and the success ratio of the radial expansion process
is
greatly increased.
In laboratory tests, a regular expansion cone, without any lubrication
grooves and flow passages, and the expansion cone 5100 were both used to
radially
expand identical coiled tubular members, each having an outside diameter of
3V2
inches. The following tables summarizes the results of this laboratory test:
LUBRICATING FLUID REGULAR EXPANSION CONE 5100
EXPANSION CONE
FORCE REQUIRED TO EXPAND TUBULAR MEMBER
PHPA Mud alone 78,000 lbf 72,000 lbf
249
CA 02613421 2007-11-20
DEMANDES OU BREVETS VOLUMINEUX
LA PRESENTE PARTIE DE CETTE DENIANDE OU CE BREVETS
COMPREND PLUS D'UN TOME.
CECI EST LE TOME DE _2
NOTE: Pour les tomes additione[s, veiliez contacter le Bureau Canadien des
Brevets.
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