U.S. patent application number 16/925132 was filed with the patent office on 2020-10-29 for tools and drilling systems for forming or servicing a wellbore.
The applicant listed for this patent is Baker Hughes, a GE company, LLC. Invention is credited to John Abhishek Raj Bomidi.
Application Number | 20200340302 16/925132 |
Document ID | / |
Family ID | 1000004946000 |
Filed Date | 2020-10-29 |
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United States Patent
Application |
20200340302 |
Kind Code |
A1 |
Bomidi; John Abhishek Raj |
October 29, 2020 |
TOOLS AND DRILLING SYSTEMS FOR FORMING OR SERVICING A WELLBORE
Abstract
A method of utilizing a wellbore tool in a subterranean
formation includes disposing a wellbore tool in a borehole. The
wellbore tool has a first body and a second body. The first body is
translated relative to the second body while exposing at least one
surface of at least one of the first and second bodies to a
lubricant comprising an organometallic compound, and a protective
coating forms over the first body and/or the second body. The
protective coating formed includes a metal originating from the
organometallic compound. A tool for forming or servicing a wellbore
includes a first body; a second body configured to translate
relative to the second body; and a lubricant adjacent the first
body and the second body.
Inventors: |
Bomidi; John Abhishek Raj;
(Spring, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Baker Hughes, a GE company, LLC |
Houston |
TX |
US |
|
|
Family ID: |
1000004946000 |
Appl. No.: |
16/925132 |
Filed: |
July 9, 2020 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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15422097 |
Feb 1, 2017 |
10711526 |
|
|
16925132 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C10N 2040/06 20130101;
C10N 2010/02 20130101; E21B 10/24 20130101; C10N 2050/08 20130101;
C10N 2030/08 20130101; C10N 2070/00 20130101; C10M 177/00 20130101;
C10N 2050/10 20130101; E21B 10/50 20130101 |
International
Class: |
E21B 10/24 20060101
E21B010/24; C10M 177/00 20060101 C10M177/00 |
Claims
1. A tool for forming or servicing a wellbore, the tool comprising:
a first body; a second body configured to translate relative to the
second body; and a lubricant adjacent the first body and the second
body, the lubricant comprising an organometallic compound
configured to coat at least one of the first body and the second
body after the tool enters the wellbore, wherein, at least
immediately prior to use of the tool for forming or servicing a
wellbore, at least one of the first body and the second body is
free of a protective coating of solid material.
2. The tool of claim 1, wherein the second body comprises a
bearing.
3. The tool of claim 1, wherein at least one of the first body and
the second body comprises an uncoated metal.
4. The tool of claim 1, wherein the lubricant is a grease.
5. The tool of claim 1, wherein the lubricant further comprises a
polyalphaolefin.
6. The tool of claim 1, wherein the lubricant has a viscosity
greater than about 100,000 cP at a temperature of about 20.degree.
C. and a sheer rate of less than about 40 s.sup.-1.
7. The tool of claim 1, wherein the organometallic compound of the
lubricant comprises a silver-organic compound.
8. The tool of claim 7, wherein the silver-organic compound
comprises [Ag(3,5-dimethyl-4-n-hexyl-pyrazolate].sub.3.
9. The tool of claim 7, wherein the silver-organic compound
comprises at least one silver atom bound with an organic
complex.
10. The tool of claim 9, wherein the organic complex comprises a
cyclic hydrocarbon comprising: one or more of nitrogen (N),
phosphorous (P), boron (B), or sulfur (S) elements; and carbon (C);
and hydrogen (H).
11. The tool of claim 10, wherein the cyclic hydrocarbon further
comprises oxygen (O).
12. The tool of claim 9, wherein the organic complex comprises at
least one of a phenol group, an alkyl group, or a pyrazole
group.
13. The tool of claim 1, wherein the lubricant further comprises a
catalyst formulated to react with the organometallic compound.
14. The tool of claim 1, wherein the lubricant further comprises
catalytic nanoparticles.
15. An earth-boring drill bit for forming or servicing a wellbore,
the earth-boring drill bit comprising a plurality of rolling cone
assemblies, at least one of the rolling cone assemblies comprising:
a rolling cone rotatably mounted to a bearing pin on a bit leg; and
a lubricant between a surface of the bearing pin opposing a surface
of the rolling cone, the lubricant comprising an organometallic
compound formulated to form a solid protective coating on at least
one of the surface of the bearing pin and the surface of the
rolling cone, wherein, at least immediately prior to disposition of
the earth-boring drill bit within the wellbore, the surface of the
bearing pin and the surface of the rolling cone are free of a
coating of solid material.
16. The earth-boring drill bit of claim 15, wherein the at least
one of the rolling cone assemblies further comprises a seal
assembly between the rolling cone and the bearing pin, the seal
assembly sealing the lubricant within a channel between the surface
of the bearing pin and the surface of the rolling cone.
17. The earth-boring drill bit of claim 16, wherein the at least
one of the rolling cone assemblies further comprises a bearing
disposed between the bearing pin and the rolling cone.
18. The earth-boring drill bit of claim 17, wherein, at least
immediately prior to the disposition of the earth-boring drill bit
within the wellbore, the surface of the bearing pin and the surface
of the rolling cone that are free of the coating of solid material
are surfaces comprising portions extending between the seal
assembly and the bearing.
19. A drilling system for forming or servicing a wellbore, the
drilling system comprising: a drill string; and a drill bit coupled
at a distal end of the drill string, the drill bit comprising: at
least one rolling cone rotatably mounted to a bearing pin of a bit
leg; a lubricant between opposing surfaces of the at least one
rolling cone and the bearing pin, the lubricant comprising an
organometallic compound formulated to form a solid coating on at
least one of the opposing surfaces during use of the drill bit, the
opposing surfaces comprising: a surface of the at least one rolling
cone; and a surface of the bearing pin, a passage internal to the
bearing pin and connected to features within the drill string
configured to deliver the lubricant to between the opposing
surfaces, wherein, at least when first assembled together, the
opposing surfaces are free of a coating of solid material.
20. The drilling system of claim 19, further comprising hardfacing
on other surfaces of the at least one rolling cone.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is a continuation of U.S. patent
application Ser. No. 15/422,097, filed Feb. 1, 2017, the disclosure
of which is hereby incorporated herein in its entirety by this
reference.
TECHNICAL FIELD
[0002] Embodiments of the present disclosure relate generally to
methods and tools for forming or enlarging wellbores, as well as
methods and tools for performing other operations within wellbores,
by forming protective coatings on surfaces of tools during use.
BACKGROUND
[0003] Wellbores are formed in subterranean formations for various
purposes including, for example, extraction of oil and gas from the
subterranean formation and extraction of geothermal heat from the
subterranean formation. Wellbores may be formed in a subterranean
formation using a drill bit such as, for example, an earth-boring
rotary drill bit. Different types of earth-boring rotary drill bits
are known in the art including, for example, fixed-cutter bits
(which are often referred to in the art as "drag" bits),
rolling-cutter bits (which are often referred to in the art as
"rock" bits), diamond-impregnated bits, and hybrid bits (which may
include, for example, both fixed cutters and rolling cutters). The
drill bit is rotated and advanced into the subterranean formation.
As the drill bit rotates, the cutters or abrasive structures
thereof cut, crush, shear, and/or abrade away the formation
material to form the wellbore. A diameter of the wellbore drilled
by the drill bit may be defined by the cutting structures disposed
at the largest outer diameter of the drill bit.
[0004] The drill bit is coupled, either directly or indirectly, to
an end of what is referred to in the art as a "drill string," which
comprises a series of elongated tubular segments connected
end-to-end that extends into the wellbore from the surface of earth
above the subterranean formations being drilled. Various tools and
components, including the drill bit, may be coupled together at the
distal end of the drill string at the bottom of the wellbore being
drilled. This assembly of tools and components is referred to in
the art as a "bottom hole assembly" (BHA).
[0005] The drill bit may be rotated within the wellbore by rotating
the drill string from the surface of the formation, or the drill
bit may be rotated by coupling the drill bit to a downhole motor,
which is also coupled to the drill string and disposed proximate
the bottom of the wellbore. The downhole motor may comprise, for
example, a hydraulic Moineau-type motor having a shaft, to which
the drill bit is mounted, that may be caused to rotate by pumping
fluid (e.g., drilling mud or fluid) from the surface of the
formation down through the center of the drill string, through the
hydraulic motor, out from nozzles in the drill bit, and back up to
the surface of the formation through the annular space between the
outer surface of the drill string and the exposed surface of the
formation within the wellbore. The downhole motor may be operated
with or without drill string rotation.
[0006] A drill string may include a number of components in
addition to a downhole motor and drill bit including, without
limitation, drill pipe, drill collars, stabilizers, measuring while
drilling (MWD) equipment, logging while drilling (LWD) equipment,
downhole communication modules, and other components.
[0007] In addition to drill strings, other tool strings may be
disposed in an existing well bore for, among other operations,
completing, testing, stimulating, producing, and remediating
hydrocarbon-bearing formations.
[0008] When drilling, completing, testing, stimulating, producing,
or remediating a wellbore, surfaces of drill string and tool string
components may be exposed to harsh conditions, and may become
damaged. For example, protective coatings formed or applied over
surfaces of tool components during manufacture and prior to
disposition in a wellbore may become scratched, exposing metal
underneath. Damage may occur on interior and/or exterior surfaces
of such components. Such damage may lead to corrosion and premature
failure of such components and to additional costs associated with
removal and repair or replacement of damaged components.
BRIEF SUMMARY
[0009] A method of utilizing a wellbore tool in a subterranean
formation includes disposing the wellbore tool in a borehole. The
wellbore tool includes a first body and a second body. The method
further includes translating the first body relative to the second
body while exposing at least one surface of at least one of the
first and second bodies to a lubricant comprising an organometallic
compound, and forming a protective coating over a surface of at
least one body selected from the group consisting of the first body
and the second body. The protective coating formed includes a metal
of the organometallic compound.
[0010] A method of coating a surface of a tool includes disposing
the tool in a borehole, the tool having at least one uncoated
surface. The method further includes contacting the at least one
uncoated surface with a lubricant adjacent a body and forming a
protective coating on the at least one uncoated surface. The
lubricant includes an organometallic compound. The protective
coating includes a metal of the organometallic compound.
[0011] A tool for forming or servicing a wellbore includes a first
body; a second body configured to translate relative to the second
body; and a lubricant adjacent the first body and the second body.
The lubricant includes an organometallic compound.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 is a simplified schematic diagram of an example of a
drilling system in accordance with an embodiment of the
disclosure.
[0013] FIG. 2 is a simplified diagram illustrating a drill bit
according to one embodiment of the disclosure.
[0014] FIG. 3 is a cross-sectional view of a portion of the drill
bit shown in FIG. 2.
DETAILED DESCRIPTION
[0015] The illustrations presented herein are not actual views of
any particular tool or drill string, but are merely idealized
representations that are employed to describe example embodiments
of the present disclosure. Additionally, elements common between
figures may retain the same numerical designation.
[0016] The following description provides specific details of
embodiments of the present disclosure in order to provide a
thorough description thereof. However, a person of ordinary skill
in the art will understand that the embodiments of the disclosure
may be practiced without employing many such specific details.
Indeed, the embodiments of the disclosure may be practiced in
conjunction with conventional techniques employed in the industry.
In addition, the description provided below does not include all
elements to form a complete structure or assembly. Only those
process acts and structures necessary to understand the embodiments
of the disclosure are described in detail below. Additional
conventional acts and structures may be used. Also note, any
drawings accompanying the application are for illustrative purposes
only, and are thus not drawn to scale. Additionally, elements
common between figures may retain the same numerical
designation.
[0017] As used herein, the terms "comprising," "including,"
"containing," "characterized by," and grammatical equivalents
thereof are inclusive or open-ended terms that do not exclude
additional, unrecited elements or method steps, but also include
the more restrictive terms "consisting of" and "consisting
essentially of" and grammatical equivalents thereof.
[0018] As used herein, the term "may" with respect to a material,
structure, feature or method act indicates that such is
contemplated for use in implementation of an embodiment of the
disclosure and such term is used in preference to the more
restrictive term "is" so as to avoid any implication that other,
compatible materials, structures, features and methods usable in
combination therewith should or must be excluded.
[0019] As used herein, the term "configured" refers to a size,
shape, material composition, and arrangement of one or more of at
least one structure and at least one apparatus facilitating
operation of one or more of the structure and the apparatus in a
predetermined way.
[0020] As used herein, the singular forms following "a," "an," and
"the" are intended to include the plural forms as well, unless the
context clearly indicates otherwise.
[0021] As used herein, the term "and/or" includes any and all
combinations of one or more of the associated listed items.
[0022] As used herein, spatially relative terms, such as "beneath,"
"below," "lower," "bottom," "above," "upper," "top," "front,"
"rear," "left," "right," and the like, may be used for ease of
description to describe one element's or feature's relationship to
another element(s) or feature(s) as illustrated in the figures.
Unless otherwise specified, the spatially relative terms are
intended to encompass different orientations of the materials in
addition to the orientation depicted in the figures.
[0023] As used herein, the term "sustained," when referring to a
duration of a temperature to which a wellbore tool or components
thereof is exposed, means and includes a period of time lasting at
least 0.1 seconds.
[0024] As used herein, the term "substantially" in reference to a
given parameter, property, or condition means and includes to a
degree that one of ordinary skill in the art would understand that
the given parameter, property, or condition is met with a degree of
variance, such as within acceptable manufacturing tolerances. By
way of example, depending on the particular parameter, property, or
condition that is substantially met, the parameter, property, or
condition may be at least 90.0% met, at least 95.0% met, at least
99.0% met, or even at least 99.9% met.
[0025] As used herein, the term "about" used in reference to a
given parameter is inclusive of the stated value and has the
meaning dictated by the context (e.g., it includes the degree of
error associated with measurement of the given parameter).
[0026] In some embodiments, disclosed methods form protective
coatings over surfaces of wellbore tools during tool use in a
subterranean formation. For example, a wellbore tool may be
disposed within a borehole. The wellbore tool may include a first
body and a second body. The first body may translate relative to
the second with a lubricant adjacent the first body and the second
body. The lubricant may include an organometallic compound. A
protective coating may be over the first body and/or the second
body during at least part of the operation. The protective coating
may be formed from the organometallic compound.
[0027] FIG. 1 is a schematic diagram of an example of a drilling
system 100 utilizing the apparatus and methods disclosed herein.
FIG. 1 shows a wellbore 110 that includes an upper section 111 with
a casing 112 installed therein and a lower section 114 that is
being drilled with a drill string 118. The drill string 118
includes a tubular member 116 that carries a drilling assembly 130
at its bottom end. The tubular member 116 may be formed by joining
drill pipe sections or may be coiled tubing. A drill bit 150 (also
referred to as the "pilot bit") is attached to the bottom end of
the drilling assembly 130 for drilling a first, smaller diameter
borehole 142 in the formation 119. A reamer bit 160 may be placed
above or uphole of the drill bit 150 in the drill string to enlarge
the borehole 142 to a second, larger diameter borehole 120. The
terms wellbore and borehole are used herein as synonyms.
[0028] The drill string 118 extends to a rig 180 at the surface
167. The rig 180 shown is a land rig for ease of explanation. The
apparatus and methods disclosed herein equally apply when an
offshore rig is used for drilling underwater. A rotary table 169 or
a top drive may rotate the drill string 118 and the drilling
assembly 130, and thus the pilot bit 150 and reamer bit 160, to
respectively drill boreholes 142 and 120. The rig 180 also includes
conventional devices, such as mechanisms to add additional sections
to the tubular member 116 as the wellbore 110 is drilled. A surface
control unit 190, which may be a computer-based unit, is placed at
the surface for receiving and processing downhole data transmitted
by the drilling assembly 130 and for controlling the operations of
the various devices and sensors 170 in the drilling assembly 130. A
drilling fluid from a source 179 thereof is pumped under pressure
through the tubular member 116 that discharges at the bottom of the
pilot bit 150 and returns to the surface via the annular space
(also referred to as the "annulus") between the drill string 118
and an inside wall of the wellbore 110.
[0029] During operation, when the drill string 118 is rotated, both
the pilot bit 150 and the reamer bit 160 rotate. The pilot bit 150
drills the first, smaller diameter borehole 142, while
simultaneously the reamer bit 160 enlarges the borehole 142 to a
second, larger diameter borehole 120. The earth's subsurface may
contain rock strata made up of different rock structures that can
vary from soft formations to very hard formations.
[0030] The pilot bit 150 may be, for example, a rolling cutter bit
200, as illustrated in FIG. 2. The rolling cutter bit 200 may
include a tool body 202 having integral leg members 204 and rolling
cones 206 mounted on heads protruding from the distal ends of
corresponding leg members 204. As the rolling cutter bit 200 is
rotated within a wellbore, the rolling cones 206 rotate on their
corresponding heads. As the rolling cones 206 rotate, cutting
structures 208 disposed on the rolling cones 206 may gouge, crush,
and scrape away formation material so as to drill the borehole in
the subterranean formation. The cutting structures 208 illustrated
in FIG. 2 may include inserts (e.g., cemented tungsten carbide
and/or polycrystalline diamond inserts), although in other
embodiments, the cutting structures 208 may have integral teeth
formed on the rolling cones 206 using machining processes.
Hardfacing material may, optionally, be applied on surfaces of the
rolling cones 206 and to the teeth.
[0031] FIG. 3 is a cross-sectional view of a portion of the rolling
cutter bit 200. Each rolling cone 206 (only one of which is shown
in FIG. 3) may be rotatably mounted to a bearing pin 214 on a bit
leg 212. One or more bearings 216 may be disposed at an interface
between the rolling cone 206 and the bearing pin 214.
[0032] The bearings 216 may include, for example, one or more
radial bearings and/or one or more axial bearings. The bearings 216
may include ball bearings and a ball plug or retainer. The rolling
cutter bit 200 may also include a seal assembly 234 between the
rolling cone 206 and the bearing pin 214. The seal assembly 234 may
include one or more of an elastomer seal, an elastomer seal
component, and a metal face seal (MFS) 236. The seal assembly 234
may seal lubricant and other fluids within a channel formed in the
rolling cone 206 or between the rolling cone 206 and the bearing
pin 214.
[0033] In some embodiments, the rolling cutter bit 200 may be
assembled with uncoated parts (i.e., parts that do not have any
protective coating thereon). For example, the rolling cone 206 and
the bearing pin 214 may be machined or otherwise formed (e.g., from
a billet of metal), and may then be assembled together uncoated. As
used herein, the term "uncoated" means free of a layer of solid
material formed over and bonded to a surface. The presence of
grease, oils, etc. does not render a surface "coated," under this
definition, if the grease or oil could be removed by wiping or with
a solvent.
[0034] During use of the rolling cutter bit 200, protective
coatings 242 may form on surfaces of the rolling cone 206 and the
bearing pin 214. In some embodiments, protective coatings may also
form on the surfaces of the bearings 216. By forming protective
coatings 242 in-situ, the surfaces of the rolling cutter bit 200
may be more evenly coated, and may be continually refreshed. Thus,
a rolling cutter bit 200 using such coatings may be relatively more
durable and operate with less internal friction than conventional
rolling cutter bits.
[0035] To form and/or add to the protective coatings 242, the
rolling cutter bit 200 may be coupled to a drill string 118 (FIG.
1), and may be operated with a lubricant formulated to form the
protective coatings 242. For example, the lubricant may be provided
to the surfaces of the rolling cone 206, the bearing pin 214,
and/or the bearings 216 by one or more internal passages 244 within
the rolling cutter bit 200. The internal passages 244 may be
connected to a fluid reservoir, pump, or other features within the
drill string 118 configured to deliver the lubricant. The lubricant
may be injected into the rolling cutter bit 200 via a port (not
shown) that communicates with the internal passage 244.
[0036] The lubricant may be a grease, having a semisolid
consistency formulated to flow under pressure, but that tends to
remain in place when pressure is released. In some embodiments, the
lubricant may be a high-temperature lubricant as disclosed in U.S.
Pat. No. 7,267,183, "Drill Bit Lubricant with Enhanced Load
Carrying/Anti Wear Properties," granted Sep. 11, 2007; U.S. Pat.
No. 4,381,824, "Drill Bit Lubrication System," granted May 3, 1983;
U.S. Patent Publication 2009/0229886, "Non-Grease Type Bearing
Lubricant," published Sep. 17, 2009; or U.S. Pat. No. 7,312,185,
"Rock Bit Grease Composition," granted Dec. 25, 2007; the entire
disclosure of each of which is incorporated herein by this
reference. The lubricant may include a base stock of a
polyalphaolefin, and may also include various other additives. The
lubricant may have a viscosity of greater than about 100,000
centipoise at a temperature of about 20.degree. C. and a sheer rate
of less than about 40 s.sup.-1. The lubricant may further include
an organometallic compound formulated to at least partially
decompose when subjected to temperatures at which the rolling
cutter bit 200 operates. For example, at a sustained temperature
from about 250.degree. C. to about 1000.degree. C., from about
500.degree. C. to about 850.degree. C., from about 550.degree. C.
to about 800.degree. C., or even from about 600.degree. C. to about
750.degree. C., the organic portion of organometallic compound may
begin to decompose, leaving the metallic portion as metal on
surfaces adjacent the lubricant. The metal may form the protective
coatings 242. The organometallic compound may be stable at
temperatures from about 20.degree. C. to about 500.degree. C., from
about 0.degree. C. to about 600.degree. C., or from about
-40.degree. C. to about 700.degree. C., for example, such that the
organometallic compound may be delivered to the rolling cutter bit
200 through components at lower temperatures without experiencing
significant decomposition. The protective coatings 242 may
therefore form over surfaces of the rolling cutter bit 200 exposed
to the lubricant at high temperatures, which may be the portions of
the rolling cutter bit 200 most in need of the protective coatings
242. In other words, the lubricant may be exposed to temperatures
greater than about 500.degree. C., greater than about 600.degree.
C., or greater than about 700.degree. C., to form the protective
coating 242.
[0037] An advantage of forming the protective coatings 242 in this
manner is that the protective coatings 242 may be continually
repaired or enhanced during drilling operations, by continuing to
provide the lubricant to the rolling cutter bit 200. The
concentration of the organometallic compound may be controlled to
control the rate of formation of the protective coatings 242. For
example, near the beginning of a drilling operation, the lubricant
may include a first concentration of the organometallic compound.
Later in the drilling operation, the lubricant may include a
second, smaller concentration of the organometallic compound. Thus,
the protective coatings 242 may initially be formed quickly by the
higher concentration of the organometallic compound, and may later
be formed more slowly to maintain the thickness and integrity of
the protective coatings 242 throughout the drilling operation.
[0038] In some embodiments, the organometallic compound may include
a silver-organic molecule, such as the trimeric silver pyrazolate
complex, [Ag(3,5-dimethyl-4-n-hexyl-pyrazolate].sub.3, as described
in "Michael Desanker et al.," "Oil-Soluble Silver-Organic Molecule
for in Situ Deposition of Lubricious Metallic Silver at High
Temperatures," ACS Appl. Mater. Interfaces, 2016, 8 (21), pp.
13637-13645, the entire disclosure of which is incorporated herein
by this reference. For example, the silver-organic molecule may
include one or more silver atoms bound with organic complexes, such
as cyclic hydrocarbons containing the elements N, P, B, and/or S,
along with C and H, and optionally O. Other elements may also be
present. The organic complexes may include various functional
groups, such as phenol groups, alkyl groups, pyrazole groups, etc.
If the organometallic compound is a silver-organometallic compound,
the protective coatings 242 formed may be substantially metallic
silver.
[0039] In some embodiments, the lubricant may include one or more
additional compounds to enable deposition of the protective
coatings 242 or to increase the rate of deposition of the
protective coatings 242. For example, an activator may be added to
the lubricant that includes a catalyst formulated to react with the
organometallic compound.
[0040] In some embodiments, the lubricant and/or the surfaces may
include catalytic nanoparticles that promote the cracking of
hydrocarbon molecules. Breaking C--C bonds may lead to deposition
of diamond or diamond-like carbon on the surfaces. For example,
surfaces may be configured to have crystalline nanometer-scale
features, which may act as a catalyst when exposed to the
lubricant. Nanocomposites and cracking of hydrocarbon molecules are
described in U.S. Patent Application Publication 2016/0145531,
"Method to Produce Catalytically Active Nanocomposite Coatings,"
published May 26, 2016, the entire disclosure of which is
incorporated herein by this reference.
[0041] If one or more of the protective coatings 242 become damaged
during use, the lubricant may repair the damaged protective
coatings 242 by depositing additional metal from the organometallic
compound. For example, if the rolling cutter bit 200 is expected to
be subjected to particularly harsh conditions, the concentration of
the organometallic compound in the lubricant may be increased
beyond the amount typically included in the lubricant. Furthermore,
the concentration of the organometallic compound may be varied
during use. For example, a drilling operation may use a first
concentration of the organometallic compound in the lubricant for a
period of time sufficient to cause an increased rate of deposition
of the protective coatings 242, followed by a second, lower
concentration of the organometallic compound in the lubricant to
cause a lower rate of deposition of the protective coatings 242.
The protective coatings 242, when exposed to the lubricant, may be
self-healing.
[0042] Furthermore, by forming the protective coatings 242 in situ
(within a wellbore or otherwise), the costs of producing the
rolling cutter bit 200 may be decreased. The protective coatings
242 may form more uniformly and without extra processing steps, as
compared to conventional methods of forming protective coatings.
The protective coatings 242 may be formed without causing
interference because the parts of the rolling cutter bit 200 are
already placed together in mutual contact before the protective
coatings 242 are formed. Tools having such protective coatings 242
may experience significant reductions in wear and friction.
[0043] While the present disclosure has been described herein with
respect to a rolling cutter bit 200 (FIG. 2), embodiments of the
disclosure have utility with different and various types and
configurations of wellbore tools, such as motors and pumps (e.g.,
having rotors that rotate within stators), hybrid bits, and any
other tools having parts that move with respect to one another. In
addition, seals and sealing surfaces may be coated using the
methods described.
[0044] Additional non limiting example embodiments of the
disclosure are described below.
[0045] Embodiment 1: A method of utilizing a wellbore tool in a
subterranean formation, the method comprising disposing a wellbore
tool in a borehole. The wellbore tool comprises a first body and a
second body. The method further comprises translating the first
body relative to the second body while exposing at least one
surface of at least one of the first and second bodies to a
lubricant comprising an organometallic compound, and forming a
protective coating over a surface of at least one body selected
from the group consisting of the first body and the second body.
The protective coating comprises a metal originating from the
organometallic compound.
[0046] Embodiment 2: The method of Embodiment 1, wherein the
organometallic compound comprises a silver-organic molecule.
[0047] Embodiment 3: The method of Embodiment 1 or Embodiment 2,
wherein the protective coating comprises silver.
[0048] Embodiment 4: The method of any of Embodiments 1 through 3,
wherein the lubricant comprises a solid.
[0049] Embodiment 5: The method of any of Embodiments 1 through 4,
wherein the lubricant comprises grease.
[0050] Embodiment 6: The method of any of Embodiments 1 through 5,
wherein forming a protective coating comprises exposing the
lubricant to a sustained temperature of greater than about
500.degree. C.
[0051] Embodiment 7: The method of Embodiment 6, wherein forming a
protective coating comprises exposing the lubricant to a sustained
temperature of greater than about 700.degree. C.
[0052] Embodiment 8: The method of any of Embodiments 1 through 7,
wherein the organometallic compound is stable at temperatures from
about 20.degree. C. to about 500.degree. C.
[0053] Embodiment 9: The method of any of Embodiments 1 through 8,
wherein the organometallic compound is formulated to decompose and
release the metal at a temperature from about 500.degree. C. to
about 850.degree. C.
[0054] Embodiment 10: The method of any of Embodiments 1 through 9,
wherein at least one of the first body and the second body is
uncoated when the wellbore tool is first disposed in the
borehole.
[0055] Embodiment 11: The method of any of Embodiments 1 through
10, wherein the first body comprises a bearing pin, and wherein the
second body comprises a roller cone.
[0056] Embodiment 12: The method of any of Embodiments 1 through
11, wherein the wellbore tool further comprises at least one
additional body between the first body and the second body.
[0057] Embodiment 13: The method of any of Embodiments 1 through
12, further comprising repairing at least a portion of the
protective coating by depositing the metal of the organometallic
compound over the at least one body while the wellbore tool is
disposed in the wellbore.
[0058] Embodiment 14: A method of coating a surface of a tool, the
method comprising disposing a tool in a borehole, the tool
comprising at least one uncoated surface; contacting the at least
one uncoated surface with a lubricant adjacent a body; and forming
a protective coating on the at least one uncoated surface. The
lubricant comprises an organometallic compound. The protective
coating comprise a metal originating from the organometallic
compound.
[0059] Embodiment 15: The method of Embodiment 14, wherein
contacting the at least one uncoated surface with a lubricant
adjacent a body comprises passing the lubricant adjacent the at
least one uncoated surface.
[0060] Embodiment 16: The method of Embodiment 14 or Embodiment 15,
wherein forming a protective coating on the at least one uncoated
surface comprises heating the lubricant and forming the metal from
at least a portion of the organometallic compound.
[0061] Embodiment 17: The method of any of Embodiments 14 through
16, wherein forming a protective coating on the at least one
uncoated surface comprises forming a silver coating on the at least
one uncoated surface.
[0062] Embodiment 18: A tool for forming or servicing a wellbore,
comprising a first body; a second body configured to translate
relative to the second body; and a lubricant adjacent the first
body and the second body. The lubricant comprises an organometallic
compound.
[0063] Embodiment 19: The tool of Embodiment 18, wherein the second
body comprises a bearing.
[0064] Embodiment 20: The tool of Embodiment 18 or Embodiment 19,
wherein at least one of the first body and the second body
comprises an uncoated metal.
[0065] While the present disclosure has been described herein with
respect to a rolling cutter bit, those of ordinary skill in the art
will recognize and appreciate that it is not so limited. Rather,
many additions, deletions, and modifications to the illustrated
embodiments may be made without departing from the scope of the
invention as hereinafter claimed, including legal equivalents
thereof. In addition, features from one embodiment may be combined
with features of another embodiment while still being encompassed
within the scope of the invention as contemplated by the inventor.
Further, embodiments of the disclosure have utility with different
and various types and configurations of wellbore tools, including
any tools having parts that move with respect to one another.
* * * * *