U.S. patent application number 10/003721 was filed with the patent office on 2003-04-24 for lubricant for use in a wellbore.
Invention is credited to Mackay, Alexander Craig, Maguire, Patrick G., Tran, Khai.
Application Number | 20030075340 10/003721 |
Document ID | / |
Family ID | 21707258 |
Filed Date | 2003-04-24 |
United States Patent
Application |
20030075340 |
Kind Code |
A1 |
Tran, Khai ; et al. |
April 24, 2003 |
Lubricant for use in a wellbore
Abstract
The present invention provides methods and apparatus for
reducing friction and preventing galling between surfaces in a
wellbore. In one aspect of the invention, mating threads are coated
with fullerene to reduce galling of the threads during make up and
break down. In another aspect, a fullerene is used between surfaces
of an expansion tool and a tubular to be expanded in order to
reduce friction and prevent galling therebetween. Preferably, the
fullerene is a spherically shaped carbon 60 molecule otherwise
known as buckyball or C.sub.60. The fullerene coating provides an
intermediate surface between two metal surfaces, thereby preventing
galling between the two surfaces. In another aspect of the
invention, the fullerene is placed between the roller of an
expander tool and the surface of the tubular to be expanded in
order to reduce friction and galling.
Inventors: |
Tran, Khai; (Pearland,
TX) ; Mackay, Alexander Craig; (Aberdeen, GB)
; Maguire, Patrick G.; (Cypress, TX) |
Correspondence
Address: |
MOSER, PATTERSON & SHERIDAN, L.L.P.
Suite 1500
3040 Post Oak Blvd
Houston
TX
77056
US
|
Family ID: |
21707258 |
Appl. No.: |
10/003721 |
Filed: |
October 23, 2001 |
Current U.S.
Class: |
166/384 ;
166/207 |
Current CPC
Class: |
E21B 17/042 20130101;
B82Y 30/00 20130101; C23C 30/00 20130101; C23C 30/005 20130101;
E21B 43/103 20130101 |
Class at
Publication: |
166/384 ;
166/207 |
International
Class: |
E21B 023/02 |
Claims
1. A method for lubricating two contacting surfaces in a wellbore,
comprising: depositing a layer of fullerene on a first surface; and
causing the first surface to contact a second surface.
2. The method of claim 1, wherein the second surface is coated with
fullerene.
3. The method of claim 1, wherein the fullerene is selected from
the group consisting of C.sub.60, C.sub.70, C.sub.76, C.sub.78,
C.sub.84, and combinations thereof.
4. A method of lubricating a surface of a downhole component,
comprising: placing a layer of C.sub.60 on the surface, whereby the
surface will contact another surface in a wellbore and create
friction therebetween.
5. An expander tool for expanding a tubular, the tool comprising: a
body having a bore longitudinally formed therethrough; and one or
more roller members radially extendable from the body, wherein the
one or more roller members include at least one coating comprising
a fullerene.
6. The expander tool of claim 5, wherein the one or more rollers
extend due to fluid pressure applied from the bore to a piston
surface formed on a roller housing.
7. The expander tool of claim 5, wherein the fullerene comprises a
carbon cage molecule.
8. The expander tool of claim 5, wherein the fullerene is selected
from the group consisting of C.sub.60, C.sub.70, C.sub.76,
C.sub.78, C.sub.84, and combinations thereof.
9. The expander tool of claim 5, wherein the coating further
comprises a carrier component.
10. The expander tool of claim 9, wherein the carrier component is
selected from the group consisting of zirconium, ceramic, and
combinations thereof.
11. The expander tool of claim 5, wherein an inner surface of the
tubular comprises the fullerene layer.
12. The expander tool of claim 11, wherein the inner surface is
expanded by the expander tool.
13. The expander tool of claim 5, wherein the fullerene is
deposited by sputtering.
14. A method for expanding a first tubular into a second tubular in
a wellbore, the first tubular and second tubular each having a top
portion and a bottom portion, comprising: positioning the first
tubular within the wellbore; running the second tubular to a
selected depth within the wellbore such that the top portion of the
second tubular overlaps with the bottom portion of the first
tubular, wherein an inner surface of the top portion of the second
tubular comprise a fullerene coating; and expanding the top portion
of the second tubular using an expander tool.
15. The method of claim 14, wherein the expander tool comprises: a
body having a bore longitudinally formed therein; and one or more
roller members radially extendable from the body.
16. The method of claim 15, wherein the one or more roller members
comprise a fullerene.
17. The method of claim 15, wherein the one or more rollers extend
due to fluid pressure applied from the bore to a piston surface
formed on a roller housing.
18. The method of claim 14, wherein the fullerene comprises a
carbon caged molecule.
19. The method of claim 14, wherein the fullerene is selected from
the group consisting of C.sub.60, C.sub.70, C.sub.76, C.sub.78,
C.sub.84, and combinations thereof.
20. The expander tool of claim 14, wherein the coating further
comprises a carrier component.
21. The expander tool of claim 20, wherein the carrier component is
selected from the group consisting of zirconium, ceramic, and
combinations thereof.
22. The method of claim 14, wherein the first tubular and the
second tubular each define a string of casing.
23. The method of claim 14, wherein the expander tool comprises a
cone shaped portion.
24. The method of claim 23, wherein the cone shaped portion
includes a fullerene coating.
25. A method of connecting a first tubular and a second tubular,
the first tubular having a threaded end for mating with a threaded
end of the second tubular, comprising: coating the threaded end of
the first tubular, the coating comprising a fullerene layer; and
connecting the threaded end of the first tubular with the threaded
end of the second tubular.
26. The method of claim 25, wherein the fullerene comprises a
carbon cage molecule.
27. The method of claim 25, wherein the fullerene is selected from
the group consisting of C.sub.60, C.sub.70, C.sub.76, C.sub.78,
C.sub.84, and combinations thereof.
28. The method of claim 25, wherein the coating further comprises a
carrier component.
29. The method of claim 28, wherein the carrier component is
selected from the group consisting of zirconium, ceramic, and
combinations thereof.
30. The method of claim 25, wherein the first tubular and the
second tubular comprise a metal selected from the group of
stainless steel, carbon steel, corrosive resistant alloy, chrome,
nickel, and combinations thereof.
31. The method of claim 25, further comprising coating the threaded
end of the second tubular, the coating comprising the fullerene
layer.
32. A method for expanding a tubular in a wellbore, comprising:
positioning the tubular within the wellbore; placing an expander
tool within the tubular at a location adjacent a portion of the
tubular to be expanded, wherein at least one of the portion of the
tubular and a portion of the expander tool comprise a fullerene
coating disposed thereupon; and expanding the tubular using the
expander tool.
33. The method of claim 32, wherein the expander tool is a
cone-shaped member movable independently within the tubular and
having an outer diameter larger than an inside diameter of the
unexpanded tubular.
34. The method of claim 32, wherein the expander tool includes at
least one radially extendable member that is extendable with the
application of fluid pressure to a backside thereof.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] The present invention relates to lubrication of components
for use in a wellbore. More particularly, the invention relates to
the lubrication of wellbore components with a fullerene. More
particularly still, the invention relates to reducing friction
encountered during operation of a downhole tool in a wellbore.
[0003] 2. Description of the Related Art
[0004] Galling of wellbore components due to friction has always
been a problem in wellbore operations. Galling is surface damage to
mating, moving, metal parts due to friction between the parts. In a
wellbore, galling can take place between moving parts of a single
component, like slips and cones of a packer or between a component
and some other surface in the wellbore that is necessarily
contacted as a component operates. Galling is also a problem for
threaded connections that may be made up on the surface of the well
and then utilized in the wellbore. Soft metals are more susceptible
to galling than hard metals, and similar metal surfaces are more
prone to galling than dissimilar metal surfaces.
[0005] Wellbore threads are often specialized and perform functions
other than simply holding parts together. For example, in
production tubing, the threaded connections between sequential
lengths of tubing are frequently required to form gas tight seals.
There are many of these "proprietary" threads that are capable of
providing a gas tight seal for tubular connections. Examples of
proprietary threads include Hydril connections, Atlas Bradford
connections, and VAM connections. Generally, these threads have
special geometric designs including shoulders that form metal to
metal seals to prevent the migration of gases though the threaded
connection. Because of the gas-sealing connections, tolerances are
especially close and the surfaces of the threads come into contact
with each other frequently as they are threaded together.
Furthermore, the proprietary threads are commonly formed of a metal
that is relatively soft, such as corrosive resistant alloys. With
unlubricated threaded connections, galling often results as the
connection is made up or taken apart.
[0006] Repair of the galled threads means reworking or replacing
the threads or the component upon which they are formed. Because
the threaded connection is typically made or unmade during assembly
or disassembly of a component and after most of the value has been
added to a component, galling can result in a complete loss of a
tool or assembly.
[0007] Galling is also a problem when expanding tubulars in a
wellbore. Expansion technology enables a tubular to be expanded and
its diameter to be increased in a wellbore. Using this method, a
liner, for example, can be hung off of an existing string of casing
without the use of a conventional slip assembly. Tubulars can be
expanded with a swedge or tapered cone that is physically pushed
through the inside of the tubular with enough force that the inside
diameter of the tubular is increased to at least the outside
diameter of the cone. More recently, expander tools are fluid
powered and are run into a wellbore on a working string. The
hydraulic expander tools include radially extendable rollers which
are urged outward radially from the body of the expander tool and
into contact with a tubular therearound. As sufficient fluid
pressure is generated upon a piston surface behind these rollers,
the tubular is expanded past its point of plastic deformation. By
rotating the expander tool in the wellbore and moving it axially, a
tubular can be expanded along a predetermined length in a
wellbore.
[0008] FIG. 1 is an exploded view of an exemplary expander tool 100
for expanding a tubular (shown as 200 in FIG. 2). A tubular is
expanded by an expander tool 100 acting outwardly against the
inside surface of the tubular. The expander tool 100 has a body 102
which is hollow and generally tubular with connectors 104 and 106
for connection to other components (not shown) of a downhole
assembly. The connectors 104 and 106 are of a reduced diameter
compared to the outside diameter of the longitudinally central body
part of the tool 100. The central body part 102 of the expander
tool 100 shown in FIG. 2 has three recesses 114, each holding a
respective roller 116. Each of the recesses 114 has parallel sides
and extends radially from a radially perforated tubular core (not
shown) of the tool 100. Each of the mutually identical rollers 116
is somewhat cylindrical and barreled. Each of the rollers 116 is
mounted by means of an axle 118 at each end of the respective
roller 116 and the axles are mounted in slidable pistons 120. The
rollers 116 are arranged for rotation about a respective rotational
axis that is parallel to the longitudinal axis of the tool 100 and
radially offset therefrom at 120-degree mutual circumferential
separations around the central body 102. The axles 118 are formed
as integral end members of the rollers 116, with the pistons 120
being radially slidable, one piston 120 being slidably sealed
within each radially extended recess 114. The inner end of each
piston 120 is exposed to the pressure of fluid within the hollow
core of the tool 100 by way of the radial perforations in the
tubular core. In this manner, pressurized fluid provided from the
surface of the well, via a working string 310, can actuate the
pistons 120 and cause them to extend outward whereby the rollers
116 contact the inner surface of a tubular to be expanded.
[0009] In one example of utilizing an expansion tool, a new section
of liner is run into the wellbore using a run-in string. As the
assembly reaches that depth in the wellbore where the liner is to
be hung, the new liner is cemented in place. Before the cement
sets, an expander tool is actuated and the liner is expanded into
contact with the existing casing therearound. By rotating the
expander tool in place, the new lower string of casing can be fixed
onto the previous upper string of casing, and the annular area
between the two tubulars is sealed.
[0010] FIG. 2 is a partial section view of a tubular 200 in a
wellbore 300. The tubular 200 is disposed coaxially within the
casing 400. An expander tool 100 is attached to a working string
310 and visible within the tubular 200. Preferably, the tubular 200
is run into the wellbore 300 with the expander tool 100 disposed
therein. The working string 310 extends below the expander tool 100
to facilitate cementing of the tubular 200 in the wellbore 300
prior to expansion of the tubular 200 into the casing 400. A remote
connection (not shown) between the working, or run-in, string 310
and the tubular 200 temporarily connects the tubular 200 to the
run-in string 310 and supports the weight of the tubular 200. For
example, the temporary connection may be a collett (not shown), and
the tubular 200 may be a string of casing.
[0011] FIG. 2 depicts the expander tool 100 with the rollers 116
retracted, so that the expander tool 100 may be easily moved within
the tubular 200 and placed in the desired location for expansion of
the tubular 200. Hydraulic fluid (not shown) is pumped from the
surface to the expander tool 100 through the working string 310.
When the expander tool 100 has been located at the desired depth,
hydraulic pressure is used to actuate the pistons (not shown) and
to extend the rollers 116 so that they may contact the inner
surface of the tubular 200, thereby expanding the tubular 200.
[0012] FIG. 3 is a partial section view of the tubular 200
partially expanded by the expander tool 100. At a given pressure,
the pistons (not shown) in the expander tool 100 are actuated and
the rollers 116 are extended until they contact the inside surface
of the tubular 200. The rollers 116 of the expander tool 100 are
further extended until the rollers 116 plastically deform the
tubular 200 into a state of permanent expansion. The working string
310 and the expander tool 100 are rotated during the expansion
process, and the tubular 200 is expanded until the tubular's outer
surface contacts the inner surface of the casing 400. The working
string 310 and expander tool 100 are then translated within the
tubular 200 until the desired length of the tubular 200 has been
expanded.
[0013] Galling takes place during expansion due to friction between
an outside surface of an outwardly extended roller and an inside
surface of a tubular being expanded. Friction between the surfaces
increases the amount of torque needed at the surface of the well to
rotate the expansion tool in the wellbore and complete the
expansion process. Increased friction causes galling of the
contacting surfaces leading to even greater friction and less
efficiency of the expansion tool.
[0014] In order to reduce friction and prevent galling in a
wellbore, lubricants have been used on threads and on surfaces
between moving parts, like the rollers of expander tools and
tubulars to be expanded. Lubricants have included grease and oil.
Sometimes, soft metals such as copper, lead, zinc, or tin are added
to the material making up contacting surfaces. The reasons for
adding the soft metals are two fold. First, the soft metals provide
a barrier that prevents galling and second, they deform under
pressure and act as a lubricant.
[0015] Methods of reducing friction and preventing galling are
disclosed in two related patents, U.S. Pat. Nos. 4,527,815 and
4,758,025, which are herein incorporated by reference. The two
patents disclose the use of electroless metal coatings on tubular
goods to eliminate galling of the threads, provide a tortuous path
as a sealing surface, and provide porous lubricant reservoirs.
While these solutions reduce friction and the likelihood of
galling, they are not completely effective.
[0016] There is a need, therefore, for a method and apparatus to
reduce the friction encountered during the operation of a downhole
tool that operates by contacting other surfaces. There is a further
need for a method and apparatus for preventing galling created by
friction between a downhole tool and other surfaces. There is yet a
further need for a method and apparatus for preventing galling in
threaded connections between tubulars and/or downhole
components.
SUMMARY OF THE INVENTION
[0017] The present invention provides methods and apparatus for
reducing friction and preventing galling between surfaces in a
wellbore. In one aspect of the invention, mating threads are coated
with fullerene to reduce galling of the threads during make up and
break down. Preferably, the fullerene is a spherically shaped
carbon 60 molecule otherwise known as buckyball or C.sub.60. The
fullerene coating provides an intermediate surface between two
metal surfaces, thereby preventing galling between the two
surfaces. In another aspect of the invention, the fullerene is
placed between the roller of an expander tool and the surface of
the tubular to be expanded in order to reduce friction and prevent
galling.
[0018] In one aspect, the present invention provides a method for
expanding a tubular in a wellbore. Initially, a tubular is disposed
in the wellbore. The tubular is then expanded using an expander
tool. The expander tool and the expanded area of the tubular
include a coating of fullerene to prevent galling of the
components. Furthermore, the fullerene coating reduces the friction
forces between the tool and the tubular, thereby increasing
efficiency.
[0019] In another aspect, threaded connections are coated with
fullerene to prevent galling. Specifically, threaded connections
for gas tight seals are coated with fullerene.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] So that the manner in which the above recited features of
the present invention are attained and can be understood in detail,
a more particular description of the invention, briefly summarized
above, may be had by reference to the embodiments thereof which are
illustrated in the appended drawings.
[0021] It is to be noted, however, that the appended drawings
illustrate only typical embodiments of this invention and are
therefore not to be considered limiting of its scope, for the
invention may admit to other equally effective embodiments.
[0022] FIG. 1 is an exploded view of an exemplary expander
tool.
[0023] FIG. 2 is a partial section view of a tubular in a wellbore
showing an expander tool attached to a working string also disposed
within the tubular.
[0024] FIG. 3 is a partial section view of the partially expanded
tubular of FIG. 2.
[0025] FIG. 4 is an illustration of carbon 60,
buckminsterfullerene.
[0026] FIG. 5 is a partial section view of a threaded connection
between two tubulars.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[0027] The aspects of the present invention are related to a
downhole tool with a coating of fullerene to reduce friction and
prevent galling between two contacting surfaces.
[0028] A fullerene is a carbon structure having each carbon atom
bonded to three other carbon atoms. The carbon atoms so joined
curve around to form a molecule with a cage-like structure and
aromatic properties. The most famous member of the fullerenes is
the buckyball, a fullerene with sixty carbon atoms. The sixty
carbon atoms of the buckyball form a shape resembling a soccer
ball. A structural diagram representing buckyball, more formally
known as buckminsterfullerene or C.sub.60, is shown in FIG. 4. The
unique shape of C.sub.60 makes it a prime candidate for use as a
lubricant to reduce friction and prevent galling.
[0029] Many methods exist for producing fullerenes. One such method
is described in U.S. Pat. No. 5,227,038, which is herein
incorporated by reference. Fullerenes are commonly derived by
contact-arc vaporization of a graphite rod, which results in the
formation of raw soot. The raw soot produced by this process
primarily comprises a mixture of two fullerenes, C.sub.60 and
C.sub.70 in a ratio of about 10 to 1 respectively, accounting for
about 5 to 10% of the total soot. Other methods of deriving
fullerene-containing soot, primarily from sooting flames, also
exist. Fullerenes such as C.sub.60, C.sub.70, C.sub.76, C.sub.78,
C.sub.84, etc., can be deposited on a substrate alone following
purification, or as a mixture with one or more fullerenes.
[0030] Fullerenes can be recovered from raw soot by extraction with
organic solvents, such as benzene or toluene, followed by
precipitative or evaporative deposition of the fullerenes on a
surface of a substrate and solvent removal. Alternatively,
fullerenes can be recovered by sublimation under vacuum with
fullerene vapor being condensed as a film upon a relatively cool
substrate surface.
[0031] Fullerenes may be coated on a surface by ion-sputtering of
purified fullerene or raw unprocessed fullerene-containing soot.
The fullerene may also be deposited by other methods known to a
person of ordinary skill in the art. Using sputtering, the
fullerene is arranged as a target within a vacuum chamber in spaced
relation to a surface to be coated. The surface may be positioned
proximate a grounded electrode, and the target positioned proximate
a conductive electrode. The chamber is back-filled with a gas at
low pressure and a source of potential is applied to the
electrodes. The potential source serves both to produce a plasma of
the gas between the spaced electrodes and to attract the gas ions
to the target. The potential causes the gas ions to bombard the
target and break or knock off fullerene atoms or molecules from the
target. These atoms or molecules settle on the surface and form a
layer of fullerene.
[0032] Referring again to FIGS. 1-3, the contact surfaces of the
rollers 116 and the tubular 200 may be coated with a layer of
fullerene. Alternatively, only one of the surfaces may be coated.
Preferably, the surfaces are coated with C.sub.60. Other possible
fullerenes for use as the coating include C.sub.70, C.sub.76,
C.sub.78, C.sub.84, and combinations thereof. In another aspect,
the coating may further comprise at least one carrier component.
The carrier components may include, but not limited to, zirconium
and ceramic, and may range from about 0% to about less than 100%,
preferably about 1% to about 50%, and most preferably about 5% to
about 25% of the composition of the coating. The coating of
fullerene may be placed upon a surface using methods known to a
person of ordinary skill in the art. In the case of sputtering a
coating onto tubular shaped components, the target can be
rod-shaped to facilitate the deposition of fullerenes on an
interior surface of the tubular.
[0033] It is believed that the coating of spherically shaped
C.sub.60 acts as molecular ball bearings between the rollers 116
and the tubular 200. As the expander tool 100 is rotated against
the tubular 200, molecular C.sub.60 breaks loose from the coating
to form a layer of molecular ball bearings. The ball bearings
reduce the friction between the rollers 116 and the tubular 200.
Consequently, less torque is needed to overcome the friction
between the rollers 116 and the tubular 200. The result is a more
efficient expansion of the tubular.
[0034] It is further believed that the C.sub.60 coating, because it
reduces friction, may also prevent galling of surfaces by acting as
a sacrificial lubricant layer disposed between the rollers 116 and
the tubular 200. Specifically, the C.sub.60 coating prevents the
two surfaces from coming into contact, thereby suppressing any
galling effect.
[0035] In another aspect, the C.sub.60 may be used with a swedge
shaped mandrel or a cone to increase the diameter of a tubular
without the use of an expander tool having extendable rollers. In
one example, a cone-shaped member is run into a wellbore and into
contact with the upper end of a tubular to be expanded In another
example, the cone can be run into the wellbore on a lower end of a
tubular run in string. The cone is designed with an outer diameter
greater than the inner diameter of the unexpanded tubular. The
outer surface of the cone may be coated with C.sub.60 to reduce
friction and prevent galling as the cone is urged into the tubular.
Alternatively, an inner surface of the tubular in contact with the
cone may be coated with C.sub.60, or both contacting surfaces may
be coated with C.sub.60.
[0036] With the coating in place, it is believed that the amount of
friction generated during the process of passing the cone into the
tubular will be significantly reduced. Additionally, any galling
between the surface of the cone and the inner surface of the
tubular will be minimized. The reduction in surface damage to the
tubular wall can be important if the surface characteristics of the
tubular after expansion are critical. In one example, a tubular is
enlarged in situ in order to form a polish bore receptacle ("PBR")
therein. The use of a coating of C.sub.60 according to the present
invention will help ensure that the PBR has surface characteristics
according to specification.
[0037] In another aspect, threaded connections may be coated with
C.sub.60 to reduce friction and avoid galling. In a threaded
connection between tubular pipe ends, either or both of the pipe
ends may be coated with C.sub.60. The C.sub.60 coating may be
deposited on the threaded connections by sputtering. Providing a
layer of C.sub.60 on at least one of the threaded surfaces
minimizes friction between the threads.
[0038] For example, the C.sub.60 coating may be used on a
production tubing to prevent galling as shown in FIG. 5. FIG. 5 is
a partial section view of a first production tubing 510 having a
first thread 515 mating with a second production tubing 520 having
a second thread 525. The production tubings 510, 520 may be
manufactured from corrosive resistance alloy consisting of softer
metals such as nickel and chrome. The threads 515, 525 formed on
the production tubings 510, 520 form a metal to metal seal to
prevent gas leakage. The outer threads 515, or the "pin," are
coated with C.sub.60 prior to being connected with the inner
threads 525, or the "box." Alternatively, both threads 515, 525 may
be coated with C.sub.60 or only one thread may be coated. In this
manner, the C.sub.60 prevents galling of the threads 515, 525 as
the connection between the tubulars is made or broken. In addition
to production tubing, the C.sub.60 may also be used on drill pipe,
casing, and other tubulars requiring threaded connections.
[0039] While the foregoing is directed to the preferred embodiment
of the present invention, other and further embodiments of the
invention may be devised without departing from the basic scope
thereof, and the scope thereof is determined by the claims that
follow.
* * * * *