Lubricant for use in a wellbore
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 C60. 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.
 1. Field of the Invention
 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.
 2. Description of the Related Art
 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.
 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.
 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.
 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.
 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.
 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.
 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.
 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.
 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.
 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.
 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.
 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.
 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
 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 C60. 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.
 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.
 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
 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.
 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.
 FIG. 1 is an exploded view of an exemplary expander tool.
 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.
 FIG. 3 is a partial section view of the partially expanded tubular of FIG. 2.
 FIG. 4 is an illustration of carbon 60, buckminsterfullerene.
 FIG. 5 is a partial section view of a threaded connection between two tubulars.DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
 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.
 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 C60, is shown in FIG. 4. The unique shape of C60 makes it a prime candidate for use as a lubricant to reduce friction and prevent galling.
 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, C60 and C70 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 C60, C70, C76, C78, C84, etc., can be deposited on a substrate alone following purification, or as a mixture with one or more fullerenes.
 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.
 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.
 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 C60. Other possible fullerenes for use as the coating include C70, C76, C78, C84, 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.
 It is believed that the coating of spherically shaped C60 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 C60 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.
 It is further believed that the C60 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 C60 coating prevents the two surfaces from coming into contact, thereby suppressing any galling effect.
 In another aspect, the C60 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 C60 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 C60, or both contacting surfaces may be coated with C60.
 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 C60 according to the present invention will help ensure that the PBR has surface characteristics according to specification.
 In another aspect, threaded connections may be coated with C60 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 C60. The C60 coating may be deposited on the threaded connections by sputtering. Providing a layer of C60 on at least one of the threaded surfaces minimizes friction between the threads.
 For example, the C60 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 C60 prior to being connected with the inner threads 525, or the “box.” Alternatively, both threads 515, 525 may be coated with C60 or only one thread may be coated. In this manner, the C60 prevents galling of the threads 515, 525 as the connection between the tubulars is made or broken. In addition to production tubing, the C60 may also be used on drill pipe, casing, and other tubulars requiring threaded connections.
 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.
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 C60, C70, C76, C78, C84, and combinations thereof.
4. A method of lubricating a surface of a downhole component, comprising:
- placing a layer of C60 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 C60, C70, C76, C78, C84, 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 C60, C70, C76, C78, C84, 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 C60, C70, C76, C78, C84, 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.