FIELD
[0001] The present disclosure relates to the field of oil and gas well production operations.
It more particularly relates to the use of coated sleeved devices to reduce friction,
wear, corrosion, erosion, and deposits in oil and gas well production operations.
Such coated sleeved oil and gas well production devices may be used in drilling rig
equipment, marine riser systems, tubular goods (casing, tubing, and drill strings),
wellhead, trees, and valves, completion strings and equipment, formation and sandface
completions, artificial lift equipment, and well intervention equipment.
BACKGROUND
[0002] Oil and gas well production suffers from basic mechanical problems that may be costly,
or even prohibitive, to correct, repair, or mitigate. Friction is ubiquitous in the
oilfield, devices that are in moving contact wear and lose their original dimensions,
and devices are degraded by erosion, corrosion, and deposits. These are impediments
to successful operations that may be mitigated by selective use of coated sleeved
oil and gas well production devices as described below.
Drilling Rig Equipment:
[0003] Following the identification of a specific location as a prospective hydrocarbon
area, production operations commence with the mobilization and operation of a drilling
rig. In rotary drilling operations, a drill bit is attached to the end of a bottom
hole assembly, which is attached to a drill string comprising drill pipe and tool
joints. The drill string may be rotated at the surface by a rotary table or top drive
unit, and the weight of the drill string and bottom hole assembly causes the rotating
bit to bore a hole in the earth. As the operation progresses, new sections of drill
pipe are added to the drill string to increase its overall length. Periodically during
the drilling operation, the open borehole is cased to stabilize the walls, and the
drilling operation is resumed. As a result, the drill string usually operates both
in the open borehole ("open-hole") and within the casing which has been installed
in the borehole ("cased-hole"). Alternatively, coiled tubing may replace drill string
in the drilling assembly. The combination of a drill string and bottom hole assembly
or coiled tubing and bottom hole assembly is referred to herein as a drill stem assembly.
Rotation of the drill string provides power through the drill string and bottom hole
assembly to the bit. In coiled tubing drilling, power is delivered to the bit by the
drilling fluid. The amount of power which can be transmitted by rotation is limited
to the maximum torque a drill string or coiled tubing can sustain.
[0004] In an alternative and unusual drilling method, the casing itself is used to drill
into the earth formations. Cutting elements are affixed to the bottom end of the casing,
and the casing may be rotated to turn the cutting elements. In the discussion that
follows, reference to the drill stem assembly will include a "drilling casing string"
that is used to drill the earth formations in this "casing-while-drilling" method.
[0005] During the drilling of a borehole through underground formations, the drill stem
assembly undergoes considerable sliding contact with both the steel casing and rock
formations. This sliding contact results primarily from the rotational and axial movements
of the drill stem assembly in the borehole. Friction between the moving surface of
the drill stem assembly and the stationary surfaces of the casing and formation creates
considerable drag on the drill stem and results in excessive torque and drag during
drilling operations. The problem caused by friction is inherent in any drilling operation,
but it is especially troublesome in directionally drilled wells or extended reach
drilling (ERD) wells. Directional drilling or ERD is the intentional deviation of
a wellbore from the vertical. In some cases the inclination (angle from the vertical)
may be as great as ninety degrees. Such wells are commonly referred to as horizontal
wells and may be drilled to a considerable depth and considerable distance from the
drilling platform.
[0006] In all drilling operations, the drill stem assembly has a tendency to rest against
the side of the borehole or the well casing, but this tendency is much greater in
directionally drilled wells because of the effect of gravity. The drill stem may also
locally rest against the borehole wall or casing in areas where the local curvature
of the borehole wall or casing is high. As the drill string increases in length or
degree of vertical deflection, the amount of friction created by the rotating drill
stem assembly also increases. Areas of increased local curvature may increase the
amount of friction generated by the rotating drill stem assembly. To overcome this
increase in friction, additional power is required to rotate the drill stem assembly.
In some cases, the friction between the drill stem assembly and the casing wall or
borehole exceeds the maximum torque that can be tolerated by the drill stem assembly
and/or maximum torque capacity of the drill rig and drilling operations must cease.
Consequently, the depth to which wells can be drilled using available directional
drilling equipment and techniques is ultimately limited by friction.
[0007] One string of pipe in sliding contact motion relative to an outer pipe, or more generally,
an inner cylinder moving within an outer cylinder, is a common geometric configuration
in several of these operations. One prior art method for reducing the friction caused
by the sliding contact between strings of pipe is to improve the lubricity of the
annular fluid. In industry operations, attempts have been made to reduce friction
through, mainly, using water and/or oil based mud solutions containing various types
of expensive and often environmentally unfriendly additives. For many of these additives
the increased lubricity gained from these additives decreases as the temperature of
the borehole increases. Diesel and other mineral oils are also often used as lubricants,
but there may be problems with the disposal of the mud, and these fluids also lose
lubricity at elevated temperatures. Certain minerals such as bentonite are known to
help reduce friction between the drill stem assembly and an open borehole. Materials
such as Teflon have been used to reduce sliding contact friction, however these lack
durability and strength. Other additives include vegetable oils, asphalt, graphite,
detergents, glass beads, and walnut hulls, but each has its own limitations.
[0008] Another prior art method for reducing the friction between pipes is to use aluminum
material for the drill string because aluminum is lighter than steel. However, aluminum
is expensive and may be difficult to use in drilling operations, it is less abrasion-resistant
than steel, and it is not compatible with many fluid types (e. g. fluids with high
pH). Additionally, the industry has developed means to "float" an inner casing string
within an outer string to run casing and liner at high inclinations, but circulation
is restricted during this operation and it is not amenable to the hole-making process.
[0009] Yet another method for reducing the friction between strings of pipe is to use a
hard facing material on the inner string (also referred to herein as hardbanding or
hardfacing).
U.S. Patent No. 4,665,996 discloses the use of hardfacing applied to the principal bearing surface of a drill
pipe, with an alloy having the composition of: 50-65% cobalt, 25-35% molybdenum, 1-18%
chromium, 2-10% silicon and less than 0.1% carbon for reducing the friction between
a string and the casing or rock. As a result, the torque needed for the rotary drilling
operation, especially directional drilling, is decreased. The disclosed alloy also
provides excellent wear resistance on the drill string while reducing the wear on
the well casing. Another form of hardbanding is WC-cobalt cermets applied to the drill
stem assembly. Other hardbanding materials include TiC, Cr-carbide, and other mixed
carbide and nitride systems. A tungsten carbide containing alloy, such as Stellite
6 and Stellite 12 (trademark of Cabot Corporation), has excellent wear resistance
as a hardfacing material but may cause excessive abrading of the opposing device.
Hardbanding may be applied to portions of the drill stem assembly using weld overlay
or thermal spray methods. In a drilling operation, the drill stem assembly, which
has a tendency to rest on the well casing, continually abrades the well casing as
the drill string rotates.
[0010] In addition to hardbanding on tool joints, certain sleeve devices have been used
in the industry. A polymer-steel based wear device is disclosed in
U.S. Patent No. 4,171,560 (Garrett, "Method of Assembling a Wear Sleeve on a Drill Pipe Assembly.") Western Well Tool
subsequently developed and currently offers Non-Rotating Protectors to control contact
between pipe and casing in deviated wellbores, holding
U.S. Patents 5,803,193,
6,250,405, and
6,378,633.
[0011] Strand et al. have patented a metal "Wear Sleeve" device (
U.S. Patent 7,028,788) that is a means to deploy hardbanding material on removable sleeves. This device
is a ring that is typically of less than one-half inch in wall thickness that is threaded
onto the pin connection of a drill pipe tool joint over a portion of the pin that
is of reduced diameter, up to the bevel diameter of the connection. The ring has internal
threads over a portion of the inner surface that are of lefthand orientation, opposite
to that of the tool joint. Threaded this way, the ring does not bind against the pin
connection body, but instead it drifts down to the box-pin connection face as the
drill string turns to the right. Arnco markets this device under the trade name "WearSleeve."
After several years of availability in the market and at least one field test, this
system has not been used widely. The methods disclosed herein provide significant
advantages over the WearSleeve device.
[0012] Arnco has devised a fixed hardbanding system typically located in the middle of a
joint of drill pipe as described in
U.S. Patent Application 2007/0209839 A1, "System and Method for Reducing Wear in Drill Pipe Sections."
[0013] Separately, a tool joint configuration in which the pin connection is held in the
slips has been deployed in the field, as opposed to the standard petroleum industry
configuration in which the box connection is held by the slips. Certain benefits have
been claimed, as documented in exemplary publications
SPE 18667 (1989) Dudman, R. A. et. al, "Pin-up Drillstring Technology: Design, Application,
and Case Histories," and
SPE 52848 (1999) Dudman, R. A. et. al, "Low-Stress Level PinUp Drillstring Optimizes
Drilling of 20,000 ft Slim-Hole in Southern Oklahoma." Dudman discloses larger pipe diameters and connection sizes for certain hole sizes
than may be used in the standard pin-down convention, because the pin connection diameter
can be made smaller than the box connection diameter and still satisfy fishing requirements.
[0014] There are many additional pieces of equipment that have metal-to-metal contact on
a drilling rig that are subject to friction, wear, erosion, corrosion, and/or deposits.
These devices include but are not limited to the following list: valves, pistons,
cylinders, and bearings in pumping equipment; wheels, skid beams, skid pads, skid
jacks, and pallets for moving the drilling rig and drilling materials and equipment;
topdrive and hoisting equipment; mixers, paddles, compressors, blades, and turbines;
and bearings of rotating equipment and bearings of roller cone bits.
[0015] Certain operations other than hole-making are often conducted during the drilling
process, including logging of the open-hole (or of the cased-hole section) to evaluate
formation properties, coring to remove portions of the formation for scientific evaluation,
capture of formation fluids at downhole conditions for fluids analyses, placing tools
against the wellbore to record acoustic signals, and other operations and methods
known to those skilled in the art. Most of these operations comprise the axial or
torsional motion of one body relative to another, wherein the two bodies are in mechanical
contact with a certain contact force and contact friction that resists the relative
motion, causing friction and wear.
Marine Riser Systems:
[0016] In a marine environment, a further complication is that the wellhead tree may be
"dry" (located above sea level on the platform) or "wet" (located on the seafloor).
In either case, conductor pipes known as "risers" are placed between the surface and
seafloor, with drill stem equipment run internal to the riser and with drilling fluid
returns in the annular space. Risers may be particularly susceptible to the issues
associated with rotating an inner pipe within an outer stationary pipe since the risers
are not fixed but may also move due to contact with not only the drill string but
also the sea environment. Drag and vortex shedding of a marine riser causes loads
and vibrations that are due in part to frictional resistance of the ocean current
around the outer surface of the marine riser.
[0017] Operations within marine riser systems often involve the axial or torsional motion
of one body relative to another, wherein the two bodies are in mechanical contact
with a certain contact force and contact friction that resists the relative motion
causing friction and wear.
Tubular Goods:
[0018] Oil-country tubular goods (OCTG) comprise drill stem equipment, casing, tubing, work
strings, coiled tubing, and risers. Common to most OCTG (but not coiled tubing) are
threaded connections, which are subject to potential failure resulting from improper
thread and/or seal interference, leading to galling in the mating connectors that
can inhibit use or reuse of the entire joint of pipe due to a damaged connection.
Threads may be shot-peened, cold-rolled, and/or chemically treated (e.g., phosphate,
copper plating, etc.) to improve their anti-galling properties, and application of
an appropriate pipe thread compound provides benefits to connection usage. However,
there are still problems today with thread galling and interference issues, particularly
with the more costly OCTG material alloys for extreme service requirements.
[0019] Operations using OCTG often involve the axial or torsional motion of one body relative
to another, wherein the two bodies are in mechanical contact with a certain contact
force and contact friction that resists the relative motion causing friction and wear.
Such motion may be required for installation after which the device may be substantially
stationary, or for repeated applications to perform some operation.
Wellhead, Trees, and Valves:
[0020] At the top of the casing, the fluids are contained by wellhead equipment, which typically
includes multiple valves and blowout preventers (BOP) of various types. Subsurface
safety valves are critical pieces of equipment that must function properly in the
event of an emergency or upset condition. Subsurface safety valves are installed downhole,
usually in the tubing string, and may be closed to prevent flow from the subsurface.
Chokes and flowlines connected to the wellhead (particularly joints and elbows) are
subject to friction, wear, corrosion, erosion, and deposits. Chokes may be cut out
by sand flowback, for example, rendering the measurement of flow rates inaccurate.
[0021] Many of these devices rely on seals and very close mechanical tolerances, including
both metal-to-metal and elastomeric seals. Many devices (sleeves, pockets, nipples,
needles, gates, balls, plugs, crossovers, couplings, packers, stuffing boxes, valve
stems, centrifuges, etc.) are subject to friction and mechanical degradation due to
corrosion and erosion, and even potential blockage resulting from deposits of scale,
asphaltenes, paraffins, and hydrates. Some of these devices may be installed downhole
or on the sea floor, and it may be impossible or very costly at best to gain service
access for repair or restoration.
[0022] Operations involving wellhead, trees, and valves often involve the axial or torsional
motion of one body relative to another, wherein the two bodies are in mechanical contact
with a certain contact force and contact friction that resists the relative motion
causing friction and wear. Such motion may be required for installation after which
the device may be substantially stationary, or for repeated applications to perform
some operation. Several of these systems also establish static or dynamic seals which
require close tolerances and smooth surfaces for leak resistance.
Completion Strings and Equipment:
[0023] With the drill well cased to prevent hole collapse and uncontrolled fluid flow, the
completion operation must be performed to make the well ready for production. This
operation involves running equipment into and out of the wellbore to perform certain
operations such as cementing, perforating, stimulating, and logging. Two common means
of conveyance of completion equipment are wireline and pipe (drill pipe, coiled tubing,
or tubing work strings). These operations may include running logging tools to record
formation and fluid properties, perforating guns to make holes in the casing to allow
hydrocarbon production or fluid injection, temporary or permanent plugs to isolate
fluid pressure, packers to facilitate setting pipe to provide a seal between the pipe
interior and annular areas, and additional types of equipment needed for cementing,
stimulating, and completing a well. Wireline tools and work strings may include packers,
straddle packers, and casing patches, in addition to packer setting tools, devices
to install valves and instruments in sidepockets, and other types of equipment to
perform a downhole operation. The placement of these tools, particularly in extended-reach
wells, may be impeded by friction drag. The final completion string left in the hole
for production is commonly referred to as the production tubing string.
[0024] Installation and use of completion strings and equipment often involves the axial
or torsional motion of one body relative to another, wherein the two bodies are in
mechanical contact with a certain contact force and contact friction that resists
the relative motion causing friction and wear. Such motion may be required for installation
after which the device may be substantially stationary, or for repeated applications
to perform some operation.
Formation and Sandface Completions:
[0025] In many wells, there is a tendency for sand or formation material to flow into the
wellbore. To prevent this from occurring, "sand screens" are placed in the well across
the completion interval. This operation may involve deploying a special-purpose large
diameter assembly comprising one of several types of sand screen mesh designs over
a central "base pipe." The screen and basepipe are frequently subject to erosion and
corrosion and may fail due to sand "cutout." Also, in high inclination wells, the
frictional drag resistance encountered while running screens into the wellbore may
be excessive and limit the application of these devices, or the length of the wellbore
may be limited by the maximum depth to which screen running operations may be conducted
due to friction resistance.
[0026] In those wells that require sand control, a sand-like propping material, "proppant,"
is pumped in the annular area between the screen and formation to prevent the formation
grains from flowing through the screens. This operation is called a "gravel pack"
or, if conducted at fracturing conditions, may be called a "frac pack." In many other
formations, often in wellbores without sand screens, fracture stimulation treatments
may be conducted in which this same or different type of propping material is injected
at fracturing conditions to create large propped fracture wings extending a significant
distance away from the wellbore to increase the production or injection rate. Frictional
resistance occurs while pumping the treatment as the proppant particles contact each
other and the constraining walls. Furthermore, the proppant particles are subject
to crushing and generating "fines" that increase the resistance to fluid flow during
production. The proppant properties, including the strength, friction coefficient,
shape, and roughness of the grain, are important to the successful execution of this
treatment and the ultimate increase in well productivity or injectivity.
[0027] Installation of sand screens and subsequent workover operations often involves the
axial or torsional motion of one body relative to another, wherein the two bodies
are in mechanical contact with a certain contact force and contact friction that resists
the relative motion causing friction and wear. Such motion may be required for installation
after which the device may be substantially stationary, or for repeated applications
to perform some operation.
Artificial Lift Equipment:
[0028] When production from a well is initiated, it may flow at satisfactory rates under
its own pressure. However, many wells at some point in their life require assistance
in lifting fluids out of the wellbore. Many methods are used to lift fluids from a
well, including: sucker rod, Corod™, and electric submersible pumps to remove fluids
from the well, plunger lifts to displace liquids from a predominantly gas well, and
"gas lift" or injection of a gas along the tubing to reduce the density of a liquid
column. Alternatively, specialty chemicals may be injected through valves spaced along
the tubing to prevent buildup of scale, asphaltene, paraffin, or hydrate deposits.
[0029] The production tubing string may include devices to assist fluid flow. Several of
these devices may rely on seals and very close mechanical tolerances, including both
metal-to-metal and elastomeric seals. Interfaces between parts (sleeves, pockets,
plugs, packers, crossovers, couplings, bores, mandrels, etc.) are subject to friction
and mechanical degradation due to corrosion and erosion, and even potential blockage
or mechanical fit interference resulting from deposits of scale, asphaltenes, paraffins,
and hydrates. In particular, gas lift, submersible pumps, and other artificial lift
equipment may include valves, seals, rotors, stators, and other devices that may fail
to operate properly due to friction, wear, corrosion, erosion, or deposits.
[0030] Installation and operation of artificial lift equipment and subsequent workover operations
often involves the axial or torsional motion of one body relative to another, wherein
the two bodies are in mechanical contact with a certain contact force and contact
friction that resists the relative motion causing friction and wear.
Well Intervention Equipment:
[0031] Downhole operations on a wellbore near the reservoir formation interval are often
required to gather data or to initiate, restore, or increase production or injection
rate. These operations involve running equipment into and out of the wellbore. Two
common means of conveyance of completion equipment and tools are wireline and pipe.
These operations may include running logging tools to record formation and fluid properties,
perforating guns to make holes in the casing to allow hydrocarbon production or fluid
injection, temporary or permanent plugs to isolate fluid pressure, packers to facilitate
a seal between intervals of the completion, and additional types of highly specialized
equipment. The operation of running equipment into and out of a well involves sliding
contact due to the relative motion of two bodies, thus creating frictional drag resistance.
[0032] Workover operations often involve the axial or torsional motion of one body relative
to another, wherein the two bodies are in mechanical contact with a certain contact
force and contact friction that resists the relative motion causing friction and wear.
Related Art:
[0033] In addition to the prior art disclosed above,
U.S. Patent Application 2008/0236842, "Downhole Oilfield Apparatus Comprising a Diamond-Like Carbon Coating and Methods
of Use," discloses applicability of DLC coatings to downhole devices with internal
surfaces that are exposed to the downhole environment. This reference does not disclose
the use of external coatings on sleeved devices and, in particular, this reference
does not discuss external application to drilling tool joint components.
[0034] Saenger and Desroches describe in EP 2090741 A1 a "coating on at least a portion of the surface of a support body" for downhole tool
operation. The types of coatings that are disclosed include DLC, diamond carbon, and
Cavidur (a proprietary DLC coating from Bekaert). The coating is specified as "an
inert material selected for reducing friction." Specific applications to logging tools
and O-rings are described. Specific benefits that are cited include friction and corrosion
reduction. Although a drill string is shown in the figures of the application, there
is no reference to applying the coating to the drill string or tool joints in this
application.
[0035] Van Den Brekel et al. disclose in WO 2008/138957 A2 a drilling method in which the casing material is 1 to 5 times harder than the drill
string material, and friction reducing additives are used in the drilling fluid. The
drill string may have poly-tetra-fluor-ethene (PTFE) applied as a friction-reducing
outer layer. This disclosure is different from the present invention in that the coatings
to be applied have hardness values greater than that of the casing material, and no
specifications for the drilling fluid are provided in the present invention.
[0036] Wei et al. also discloses the use of coatings on the internal surfaces of tubular
structures (
U. S. Patent 6,764,714, "Method for Depositing Coatings on the Interior Surfaces of Tubular Walls," and
U. S. Patent 7,052,736, "Method for Depositing Coatings on the Interior Surfaces of Tubular Structures").
Tudhope et al. also have developed means to coat internal surfaces of an object, including
for example
U. S. Patent 7,541,069, "Method and System for Coating Internal Surfaces Using Reverse-Flow Cycling."
[0037] Griffo discloses the use of superabrasive nanoparticles on bits and bottom-hole assembly
components in
U. S. Patent Application 2008/0127475, "Composite Coating with Nanoparticles for Improved Wear and Lubricity in Downhole
Tools."
[0038] Gammage et al. discloses spray metal application to the external surface of downhole
tool components in
U. S. Patent 7,487,840.
[0039] Thornton discloses the use of Tungsten Disulphide (WS
2) on downhole tools in
WO 2007/091054, "Improvements In and Relating to Downhole Tools."
[0040] The use of coatings on bits and bit seals has been disclosed, for example in
U.S. Patent 7,234,541, "DLC Coating for Earth-Boring Bit Seal Ring,"
U.S. Patent 6,450,271, "Surface Modifications for Rotary Drill Bits," and
U. S. Patent 7,228,922, "Drill Bit."
[0041] In addition, the use of DLC coatings in non-oilfield applications has been disclosed
in
U.S. Patent 6,156,616, "Synthetic Diamond Coatings with Intermediate Bonding Layers and Methods of Applying
Such Coatings" and
U.S. Patent 5,707,717, "Articles Having Diamond-Like Protective Film."
[0042] U.S. Patent Application 2004/0188147 (Mitchell et al.) relates to a drill pipe protector having a tubular sleeve that is attached to a
section of drill pipe and resides over the outer diameter of the drill pipe while
moving within an associated well casing or well hole. The sleeve has low-friction
end pads positioned on the ends of the sleeve and the end of an adjacent thrust bearing
collar used to hold the sleeve in place on the drill pipe.
Need for the Disclosure:
[0043] Given the expansive nature of these broad requirements for production operations,
there is a need for the application of new coating material technologies that protect
devices from friction, wear, corrosion, erosion, and deposits resulting from sliding
contact between two or more devices and fluid flowstreams that may contain solid particles
traveling at high velocities. This need requires novel materials that combine high
hardness with a capability for low coefficient of friction (COF) when in contact with
an opposing surface. Furthermore, the use of
sleeved devices is a practical and economic means to deploy such coatings in oil and
gas well production equipment. If such coating material can also provide a low energy
surface and low friction coefficient against the borehole wall, then this novel material
coating may enable ultra-extended reach drilling, reliable and efficient operations
in difficult environments, including offshore and deepwater applications, and generate
cost reduction, safety, and operational improvements throughout oil and gas well production
operations. As envisioned, the use of these coatings on sleeved well production devices
could have widespread application and provide significant improvements and extensions
to well production operations.
[0044] Therefore, there exists a need for coated sleeved oil and gas well production devices.
First, the methods to apply the inventive coatings on production devices may require
that the body be enclosed in a chamber. This may be a very restrictive requirement
for many oilfield components. For example, the geometry of long pipe sections is cumbersome
for such chambers. This is also not likely to be very efficient since the surface
area to be coated may be a small fraction of the total surface area of the main body.
Coated sleeve elements of a coated sleeved device can be transported to the field
location and installed on the production equipment with less cost than alternative
means of deploying such low-friction coatings. Also, in certain applications for which
either the sleeve element or the coating needs to be replaced or refurbished, a sleeved
system configuration is economical, with minimal transportation requirements and equipment
downtime. The sleeve element itself may be comprised of different material than the
body to which it is proximal. The sleeve element may be subjected to high temperatures
and other environmental conditions during the coating process that would cause damage
to the other elements of the system. Sleeve elements of a coated sleeved device can
be coated with low friction materials more efficiently and with a broader range of
possible coating types than attempting to coat larger pieces of equipment, facilitating
utilization of low-friction coatings to improve the effective mechanical properties
of these devices. The prior art does not disclose an efficient means to address these
problems, and the inventive methods will enable the use of low-friction coatings in
oil and gas well production devices.
SUMMARY
[0045] According to the present disclosure, an advantageous coated sleeved oil and gas well
production device comprising: one or more cylindrical bodies, one or more sleeves
proximal to the outer diameter or inner diameter of the one or more cylindrical bodies,
and a coating on at least a portion of the inner sleeve surface, the outer sleeve
surface, or a combination thereof of the one or more sleeves, wherein the one or more
sleeves include hardbanding on at least a portion of an exposed outer surface, wherein
the coating is on top of the hardbanding, and wherein the one or more sleeves further
include one or more buttering layers interposed between the exposed outer surface
and the coating or between the exposed outer surface and the hardbanding on at least
a portion of the exposed surface, and wherein the coating is chosen from an amorphous
alloy, a heat-treated electroless or electro plated based nickel-phosphorous composite
with a phosphorous content greater than 12 wt%, graphite, MoS
2, WS
2, a fullerene based composite, a boride based cermet, a quasicrystalline material,
a diamond based material, diamond-like-carbon (DLC), boron nitride, and combinations
thereof.
[0046] A further aspect of the present disclosure relates to the use of such a coated sleeved
oil and gas well production device in well construction, completion, or production
operations.
[0047] These and other features and attributes of the disclosed coated sleeved oil and gas
well production devices, and methods of using such sleeved devices for reducing friction,
wear, corrosion, erosion, and deposits in such application areas, and their advantageous
applications and/or uses will be apparent from the detailed description which follows,
particularly when read in conjunction with the figures appended hereto.
BRIEF DESCRIPTION OF DRAWINGS
[0048] To assist those of ordinary skill in the relevant art in making and using the subject
matter hereof, reference is made to the appended drawings, wherein:
Figure 1 depicts an oil and gas well production system that employs well production devices
in the individual well construction, completion, stimulation, workover, and production
phases of the overall production process.
Figure 2 depicts exemplary application of a coating applied to a sleeved drill stem assembly
for subterreaneous drilling applications.
Figure 3 depicts exemplary application of coatings applied to bottomhole assembly devices
that may be adapted to use coated sleeves, in this case reamers, stabilizers, mills,
and hole openers.
Figure 4 depicts exemplary application of a coating applied to a marine riser system with
coated sleeve wear bushings.
Figure 5 depicts exemplary application of coated sleeves applied to polished rods, sucker
rods, and pumps used in downhole pumping operations.
Figure 6 depicts exemplary application of coated sleeves applied to perforating guns, packers,
and logging tools.
Figure 7 depicts exemplary application of coatings applied to wire rope and wire line and
bundles of stranded cables. Coated sleeves may be used in the bushings to facilitate
smooth wireline operations.
Figure 8 depicts exemplary application of a coating applied to a basepipe and screen assembly
used in gravel pack sand control operations and screens used in solids control equipment,
illustrating coated sleeves that may be used to assist sliding of the screen into
the wellbore.
Figure 9 depicts exemplary application of a coated sleeves applied to wellhead and valve assemblies,
where the sleeve device may be used in valves to provide a seal at lower operating
forces and loads.
Figure 10 depicts exemplary application of coated sleeves applied to an orifice meter, a choke,
and a turbine meter.
Figure 11 depicts exemplary application of a coated sleeves applied to the grapple and overshot
of a washover fishing tool.
Figure 12 depicts exemplary application of a coating applied to a threaded connection and illustrates
thread galling.
Figure 13 illustrates the exemplary application of a coated sleeve element in a coated sleeved
drill string connection, showing both pin-down and pin-up connection configurations
and additional possible sleeve parameters.
Figure 14 depicts, schematically, the rate of penetration (ROP) versus weight on bit (WOB)
during subterraneous rotary drilling.
Figure 15 depicts the relationship between coating COF and coating hardness for some of the
coatings disclosed herein versus steel base case.
Figure 16 depicts a representative stress-strain curve showing the high elastic limit of amorphous
alloys compared to that of crystalline metals/alloys.
Figure 17 depicts a ternary phase diagram of amorphous carbons.
Figure 18 depicts a schematic illustration of the hydrogen dangling bond theory.
Figure 19 depicts the friction and wear performance of DLC coating in a dry sliding wear test.
Figure 20 depicts the friction and wear performance of the DLC coating in oil based mud.
Figure 21 depicts the friction and wear performance of DLC coating at elevated temperature
(66°C (150°F)) sliding wear test in oil based mud.
Figure 22 depicts the friction performance of DLC coating at elevated temperatures (66°C (150°F)
and 93°C (200°F)) in comparison to that of uncoated bare steel and hardbanding in
oil based mud.
Figure 23 depicts the velocity-weakening performance of DLC coating in comparison to an uncoated
bare steel substrate.
Figure 24 depicts SEM cross-sections of single layer and multi-layered DLC coatings disclosed
herein.
Figure 25 depicts water contact angle for DLC coatings versus uncoated 4142 steel.
Figure 26 depicts an exemplary schematic of hybrid DLC coating on hardbanding for drill stem
assemblies.
DEFINITIONS
[0049] "Annular isolation valve" is a valve at the surface to control flow from the annular
space between casing and tubing.
[0050] "Asphaltenes" are heavy hydrocarbon chains that may be deposited on the walls of
pipes and other flow equipment and therefore create a flow restriction.
[0051] "Basepipe" is a liner that serves as the load-bearing device of a sand control screen.
The screens are attached to the outside of the basepipe. At least a portion of the
basepipe may be pre-perforated, slotted, or equipped with an inflow control device.
The basepipe is fabricated in jointed sections that are threaded for makeup while
running in hole.
[0052] "Bearings and bushings" are used to provide a low friction surface for two devices
to move relative to each other in sliding contact, especially to allow relative rotational
motion.
[0053] "Blast joints" are thicker-walled pipe used across flowing perforations or in a wellhead
across a fluid inlet during a stimulation treatment. The greater wall thickness and/or
material hardness resists being completely eroded through due to sand or proppant
impingement.
[0054] "Bottom hole assembly" (BHA) is comprised of one or more devices, including but not
limited to: stabilizers, variable-gauge stabilizers, back reamers, drill collars,
flex drill collars, rotary steerable tools, roller reamers, shock subs, mud motors,
logging while drilling (LWD) tools, measuring while drilling (MWD) tools, coring tools,
under-reamers, hole openers, centralizers, turbines, bent housings, bent motors, drilling
jars, acceleration jars, crossover subs, bumper jars, torque reduction tools, float
subs, fishing tools, fishing jars, washover pipe, logging tools, survey tool subs,
non-magnetic counterparts of any of these devices, and combinations thereof and their
associated external connections.
[0055] "Casing" is pipe installed in a wellbore to prevent the hole from collapsing and
to enable drilling to continue below the bottom of the casing string with higher fluid
density and without fluid flow into the cased formation. Typically, multiple casing
strings are installed in the wellbore of progressively smaller diameter.
[0056] "Casing centralizers" are banded to the outside of casing as it is being run in hole.
Centralizers are often equipped with steel springs or metal fingers that push against
the formation to achieve standoff from the formation wall, with an objective to centralize
the casing to provide a more uniform annular space around the casing to achieve a
better cement seal. Centralizers may include finger-like devices to scrape the wellbore
to dislodge drilling fluid filtercake that may inhibit direct cement contact with
the formation.
[0057] "Casing-while-drilling" refers to a relatively new and unusual method to drill using
the casing instead of a removable drill string. When the hole section has reached
depth, the casing is left in position, an operation is performed to remove or displace
the cutting elements at the bottom of the casing, and a cement job may then be pumped.
[0058] "Chemical injection system" is used to inject chemical inhibitors into the wellbore
to prevent buildup of scale, methane hydrates, or other deposits in the wellbore that
would restrict production.
[0059] "Choke" is a device to restrict the rate of flow. Wells are commonly tested on a
specific choke size, which may be as simple as a plate with a hole of specified diameter.
When sand or proppant flow through a choke, the hole may be eroded and the choke size
may change, rendering inaccurate flow rate measurements.
[0060] "Coaxial" refers to two or more objects having axes which are substantially identical
or along the same line. "Non-coaxial" refers to objects which have axes that may be
offset but substantially parallel or may otherwise not be along the same line.
[0061] "Completion sliding sleeves" are devices that are installed in the completion string
that selectively enable orifices to be opened or closed, allowing productive intervals
to be put into communication with the tubing or not, depending on the state of the
sleeve. In long term use, the success of operating sliding sleeves depends on the
resistance to operating the sleeve due to friction, wear, deposits, erosion, and corrosion.
[0062] "Complex geometry" refers to an object that is not substantially comprised of a single
primitive geometry such as a sphere, cylinder, or cube. Complex geometries may be
comprised of multiple simple geometries, such as a cylinder, cube, or sphere with
many different radii, or may be comprised of simple primitives and other complex geometries.
[0063] "Connection pin" is a piece of pipe with the threads on the external surface of the
pipe.
[0064] "Connection box" is a piece of pipe with the threads on the internal surface of the
pipe.
[0065] "Contact rings" are devices attached to components of logging tools to achieve standoff
of the tool from the wall of the casing or formation. For example, contact rings may
be installed at joints in a perforating gun to achieve a standoff of the gun from
the casing wall, for example in applications such as "Just-In-Time Perforating" (
PCT Application No. WO2002/103161A2).
[0066] "Contiguous" refers to objects which are adjacent to one another such that they may
share a common edge or face. "Non-contiguous" refers to objects that do not have a
common edge or face because they are offset or displaced from one another. For example,
tool joints are larger diameter cylinders that are non-contiguous because a smaller
diameter cylinder, the drill pipe, is positioned between the tool joints.
[0067] "Control lines" and "conduits" are small diameter tubing that may be run external
to a tubing string to provide hydraulic pressure, electrical voltage or current, or
a fiberoptic path, to one or more downhole devices. Control lines are used to operate
subsurface safety values, chokes, and valves. An injection line is similar to a control
line and may be used to inject a specialty chemical to a downhole valve for the purpose
of inhibition of scale, asphaltene, paraffin, or hydrate formation, or for friction
reduction.
[0068] "Corod™" is a continuous coiled tubular used as a sucker rod in rod pumping production
operations.
[0069] "Coupling" is a connecting device between two pieces of pipe, often but not exclusively
a separate piece that is threadably adapted to two longer pieces that the coupling
joins together. For example, a coupling is used to join two pieces of sucker rods
in artificial lift rod pumping equipment.
[0070] "Cylinder" is (1) a surface or solid bounded by two parallel planes and generated
by a straight line moving parallel to the given planes and tracing a curve bounded
by the planes and lying in a plane perpendicular or oblique to the given planes, and/or
(2) any cylinderlike object or part, whether solid or hollow (source: www.dictionary.com).
[0071] "Downhole tools" are devices that are often run retrievably into a well, or possibly
fixed in a well, to perform some function in the wellbore. Some downhole tools may
be run on a drill stem, such as Measurement While Drilling (MWD) devices, whereas
other downhole tools may be run on wireline, such as formation logging tools or perforating
guns. Some tools may be run on either wireline or pipe. A packer is a downhole tool
that may be run on pipe or wireline to be set in the wellbore to block flow, and it
may be removable or fixed. There are many downhole tool devices that are commonly
used in the industry.
[0072] "Drill collars" are heavy wall pipe in the bottom hole assembly near the bit. The
stiffness of the drill collars help the bit to drill straight, and the weight of the
collars are used to apply weight to the bit to drill forward.
[0073] "Drill stem" is defined as the entire length of tubular pipes, composed of the kelly
(if present), the drill pipe, and drill collars, that make up the drilling assembly
from the surface to the bottom of the hole. The drill stem does not include the drill
bit. In the special case of casing-while-drilling operations, the casing string that
is used to drill into the earth formations will be considered part of the drill stem.
[0074] "Drill stem assembly" is defined as a combination of a drill string and bottom hole
assembly or coiled tubing and bottom hole assembly. The drill stem assembly does not
include the drill bit.
[0075] "Drill string" is defined as the column, or string of drill pipe with attached tool
joints, transition pipe between the drill string and bottom hole assembly including
tool joints, heavy weight drill pipe including tool joints and wear pads that transmits
fluid and rotational power from the top drive or kelly to the drill collars and the
bit. In some references, but not in this document, the term "drill string" includes
both the drill pipe and the drill collars in the bottomhole assembly.
[0076] "Elastomeric seal" is used to provide a barrier between two devices, usually metal,
to prevent flow from one side of the seal to the other. The elastomeric seal is chosen
from one of a class of materials that are elastic or resilient.
[0077] "Elbows, tees, and couplings" are commonly used pipe equipment for the purpose of
connecting flowlines to complete a flowpath for fluids, for example to connect a wellbore
to surface production facilities.
[0078] "Expandable tubulars" are tubular goods such as casing strings and liners that are
slightly undergauge while running in hole. Once in position, a larger diameter tool,
or expansion mandrel, is forced down the expandable tubular to deform it to a larger
diameter.
[0079] "Gas lift" is a method to increase the flow of hydrocarbons in a wellbore by injecting
gas into the tubing string through gas lift valves. This process is usually applied
to oil wells, but could be applied to gas wells with high fractions of water production.
The added gas reduces the hydrostatic head of the fluid column.
[0080] "Glass fibers" are often run in small control lines, both downhole and return to
surface, for the measurement of downhole properties, such as temperature or pressure.
Glass fibers may be used to provide continuous readings at fine spatial samplings
along the wellbore. The fiber is often pumped down one control line, through a "turnaround
sub," and up a second control line. Friction and resistance passing through the turnaround
sub may limit some fiberoptic installations.
[0081] "Inflow control device" (ICD) is an adjustable orifice, nozzle, or flow channel in
the completion string across the formation interval to enable the rate of flow of
produced fluids into the wellbore. This may be used in conjunction with additional
measurements and automation in a "smart" well completion system.
[0082] "Jar" is a downhole tool that is used to apply a large axial load, or shock, when
triggered by the operator. Some jars are fired by setting weight down, and others
are fired when pulled up. The firing of the jar is usually done to move pipe that
has become stuck in the wellbore.
[0083] "Kelly" is a flat-sided polygonal piece of pipe that passes through the drilling
rig floor on rigs equipped with older rotary table equipment. Torque is applied to
this four-, six-, or perhaps eight-sided piece of pipe to rotate the drill pipe that
is connected below.
[0084] "Logging tools" are instruments that are typically run in a well to make measurements,
for example during drilling on the drill stem or in open or cased hole on wireline.
The instruments are installed in a series of carriers configured to run into a well,
such as cylindrical-shaped devices, that provide environmental isolation for the instruments.
[0085] "Makeup" is the process of screwing together the pin and box of a pipe connection
to effect a joining of two pieces of pipe and to make a seal between the inner and
outer portions of the pipe.
[0086] "Mandrel" is a cylindrical bar or shaft that fits within an outer cylinder. A mandrel
may be the main actuator in a packer that causes the gripping units, or "slips," to
move outward to contact the casing. The term mandrel may also refer to the tool that
is forced down an expandable tubular to deform it to a larger diameter. Mandrel is
a generic term used in several types of oilfield devices.
[0087] "Metal mesh" for a sand control screen is comprised of woven metal filaments that
are sized and spaced in accordance with the corresponding formation sand grain size
distribution. The screen material is generally corrosion resistant alloy (CRA) or
carbon steel.
[0088] "Mazeflo™" completion screens are sand screens with redundant sand control and baffled
compartments. MazeFlo self-mitigates any mechanical failure of the screen to the local
compartment maze, while allowing continued hydrocarbon flow through the undamaged
sections. The flow paths are offset so that the flow makes turns to redistribute the
incoming flow momentum (for example, refer to
U.S. Patent No. 7,464,752).
[0089] "Moyno™ pumps" and "progressive cavity pumps" are long cylindrical pumps installed
in downhole motors that generate rotary torque in a shaft as the fluid flows between
the external stator and the rotor attached to the shaft. There is usually one more
lobe on the stator than the rotor, so the force of the fluid traveling to the bit
forces the rotor to turn. These motors are often installed close to the bit. Alternatively,
in a downhole pumping device, power can be applied to turn the rotor and thereby pump
fluid.
[0090] "Packer" is a tool that may be placed in a well on a work string, coiled tubing,
production string, or wireline. Packers provide fluid pressure isolation of the regions
above and below the packer. In addition to providing a hydraulic seal that must be
durable and withstand severe environmental conditions, the packer must also resist
the axial loads that develop due to the fluid pressure differential above and below
the packer.
[0091] "Packer latching mechanism" is used to operate a packer, to make it release and engage
the slips by axial movement of the pipe to which it is connected. When engaged, the
slips are forced outwards into the casing wall, and the teeth of the slips are pressed
into the casing material with large forces. A wireline packer is run with a packer
setting tool that pulls the mandrel to engage the slips, after which the packer setting
tool is disengaged from the packer and retrieved to the surface.
[0092] "MP35N" is a metal alloy consisting primarily of nickel, cobalt, chromium, and molybdenum.
MP35N is considered highly corrosion resistant and suitable for hostile downhole environments.
[0093] "Paraffin" is a waxy component of some crude hydrocarbons that may be deposited on
the walls of wellbores and flowlines and thereby cause flow restrictions.
[0094] "Pin-down connection" is currently the standard drilling configuration in which the
box connection is held by the slips at the surface and the pin connection is facing
down during connection makeup.
[0095] "Pin-up connection" is a drilling tool assembly that is oriented such that the pin
connection is held in the slips at surface while making a connection, instead of the
standard configuration in which the box connection is held by the slips. This reconfiguration
may or may not require a change in the thread direction of the connection, i.e. left-handed
or right-handed threads.
[0096] "Pistons" and "piston liners" are cylinders that are used in pumps to displace fluids
from an inlet to an outlet with corresponding fluid pressure increase. The liner is
the sleeve within which the piston reciprocates. These pistons are similar to the
pistons found in the engine of a car.
[0097] "Plunger lift" is a device that moves up and down a tubing string to purge the tubing
of water, similar to a pipeline "pigging" operation. With the plunger lift at the
bottom of the tubing, the pig device is configured to block fluid flow, and therefore
it is pushed uphole by fluid pressure from below. As it moves up the wellbore it displaces
water because the water is not allowed to separate and flow past the plunger lift.
At the top of the tubing, a device triggers a change in the plunger lift configuration
such that it now bypasses fluids, whereupon gravity pulls it down the tubing against
the upwards flowstream. Friction and wear are important parameters in plunger lift
operation. Friction reduces the speed of the plunger lift falling or rising, and wear
of the outer surface provides a gap that reduces the effectiveness of the device when
traveling uphole.
[0098] "Production device" is a broad term defined to include any device related to the
drilling, completion, stimulation, workover, or production of an oil and/or gas well.
A production device includes any device described herein used for the purpose of oil
or gas production. For convenience of terminology, injection of fluids into a well
is defined to be production at a negative rate. Therefore, references to the word
"production" will include "injection" unless stated otherwise.
[0099] "Reciprocating seal assembly" is a seal that is designed to maintain pressure isolation
while two devices are displaced axially.
[0100] "Roller cone bit" is an earth-boring device equipped with conical shaped cutting
elements, usually three, to make a hole in the ground.
[0101] "Rotating seal assembly" is a seal that is designed to maintain pressure isolation
while two devices are displaced in rotation.
[0102] "Sand probe" is a small device inserted into a flowstream to assess the amount of
sand content in the stream. If the sand content is high, the sand probe may be eroded.
[0103] "Scale" is a deposit of minerals (e.g. calcium carbonate) on the walls of pipes and
other flow equipment that may build up and cause a flow restriction.
[0104] "Service tools" for gravel pack operations include a packer crossover tool and tailpipe
to circulate down the workstring, around the liner and tailpipe, and back to the annulus.
This permits placement of slurry opposite the formation interval. More generally,
the gravel pack service tool is a group of tools that carry the gravel pack screens
to TD, sets and tests the packer, and controls the flow path of the fluids pumped
during gravel pack operations. The service tool includes the setting tool, the crossover,
and the seals that seal into a packer bore. It can include an anti-swab device and
a fluid loss or reversing valve.
[0105] "Shock sub" is a modified drill collar that has a shock absorbing spring-like element
to provide relative axial motion between the two ends of the shock sub. A shock sub
is sometimes used for drilling very hard formations in which high levels of axial
shocks may occur.
[0106] "Shunt tubes" are external or internal tubes run in a sand control screen to divert
the gravel pack slurry flow over long or multi-zone completion intervals until a complete
gravel pack is achieved. See, for example,
U.S. Patents Nos. 4,945,991,
5,113,935, and
PCT Patent Publication Nos. WO2007/092082,
WO2007/092083,
WO2007/126496, and
WO2008/060479.
[0107] "Sidepocket" is an offset heavy-wall sub in the tubing for placing gas lift valves,
temperature and pressure probes, injection line valves, etc.
[0108] "Sleeve" is a tubular part designed to fit over another part. The inner and outer
surfaces of the sleeve may be circular or non-circular in cross-section profile. The
inner and outer surfaces may generally have different geometries, i.e. the outer surface
may be cylindrical with circular cross-section, whereas the inner surface may have
an elliptical or other non-circular cross-section. Alternatively, the outer surface
may be elliptical and the inner surface circular, or some other combination. More
generally, a sleeve may be considered to be a generalized hollow cylinder with one
or more radii or varying cross-sectional profiles along the axial length of the cylinder.
[0109] "Sliding contact" refers to frictional contact between two bodies in relative motion,
whether separated by fluids or solids, the latter including particles in fluid (bentonite,
glass beads, etc) or devices designed to cause rolling to mitigate friction. A portion
of the contact surface of two bodies in relative motion will always be in a state
of slip, and thus sliding.
[0110] "Smart well" is a well equipped with devices, instrumentation, and controls to enable
selective flow from specified intervals to maximize production of desirable fluids
and minimize production of undesirable fluids. The flow rates may be adjusted for
additional reasons, such as to control the drawdown or pressure differential for geomechanics
reasons.
[0111] "Stimulation treatment" lines are pipe used to connect pumping equipment to the wellhead
for the purpose of conducting a stimulation treatment.
[0112] "Subsurface safety valve" is a valve installed in the tubing, often below the seafloor
in an offshore operation, to shut off flow. Sometimes these valves are set to automatically
close if the rate exceeds a set value, for instance if containment was lost at the
surface.
[0113] "Sucker rods" are steel rods that connect a beam-pumping unit at the surface with
a sucker-rod pump at the bottom of a well. These rods may be jointed and threaded
or they may be continuous rods that are handled like coiled tubing. As the rods reciprocate
up and down, there is friction and wear at the locations of contact between the rod
and tubing.
[0114] "Surface flowlines" are pipe used to connect the wellhead to production facilities,
or alternatively, for discharge of fluid to the pits or flare stack.
[0115] "Threaded connection" is a means to connect pipe sections and achieve a hydraulic
seal by mechanical interference between interlaced threaded, or machined (e.g., metal-to-metal
seal), parts. A threaded connection is made up, or assembled, by rotating one device
relative to another. Two pieces of pipe may be adapted to thread together directly,
or a connector piece referred to as a coupling may be screwed onto one pipe, followed
by screwing a second pipe into the coupling.
[0116] "Tool joint" is a tapered threaded coupling element for pipe that is usually made
of a special steel alloy wherein the pin and box connections (externally and internally
threaded, respectively) are fixed to either ends of the pipe. Tool joints are commonly
used on drill pipe but may also be used on work strings and other OCTG, and they may
be friction welded to the ends of the pipe.
[0117] "Top drive" is a method and equipment used to rotate the drill pipe from a drive
system located on a trolley that moves up and down rails attached to the drilling
rig mast. Top drive is the preferred means of operating drill pipe because it facilitates
simultaneous rotation and reciprocation of pipe and circulation of drilling fluid.
In directional drilling operations, there is often less risk of sticking the pipe
when using top drive equipment.
[0118] "Tubing" is pipe installed in a well inside casing to allow fluid flow to the surface.
[0119] "Valve" is a device that is used to control the rate of flow in a flowline. There
are many types of valve devices, including check valve, gate valve, globe valve, ball
valve, needle valve, and plug valve. Valves may be operated manually, remotely, or
automatically, or a combination thereof. Valve performance is highly dependent on
the seal established between close-fitting mechanical devices.
[0120] "Valve seat" is the static surface upon which the dynamic seal rests when the valve
is operated to prevent flow through the valve. For example, a flapper of a subsurface
safety valve will seal against the valve seat when it is closed.
[0121] "Wash pipe" in a sand control operation is a smaller diameter pipe that is run inside
the basepipe after the screens are placed in position across the formation interval.
The wash pipe is used to facilitate annular slurry flow across the entire completion
interval, take the return flow during the gravel packing treatment, and leave gravel
pack in the screen-wellbore annulus.
[0122] "Washer" is typically a flat ring that is used to prevent leakage, distribute pressure,
or make a joint tight, as under the head of a nut or bolt, or perhaps in a threaded
connection of another part, such as a valve. A washer may be considered as a degenerate
form of a sleeve in which the diametral dimension is greater than the axial dimension.
[0123] "Wireline" is a cable that is used to run tools and devices in a wellbore. Wireline
is often comprised of many smaller strands twisted together, but monofilament wireline,
or "slick line," also exists. Wireline is usually deployed on large drums mounted
on logging trucks or skid units.
[0124] "Work strings" are jointed pieces of pipe used to perform a wellbore operation, such
as running a logging tool, fishing materials out of the wellbore, or performing a
cement squeeze job.
DETAILED DESCRIPTION
[0126] All numerical values within the detailed description and the claims herein are modified
by "about" or "approximately" the indicated value, and take into account experimental
error and variations that would be expected by a person having ordinary skill in the
art.
[0127] Reconfiguration of equipment to utilize sleeves at designated locations, such as
the point of contact between two or more bodies, facilitates the use of this low-friction
technology. The use of coatings on sleeve elements provides a small piece that can
be readily placed into a manufacturing device or chamber to apply such coating, with
improved economics. Removable sleeves may be replaced more readily within the context
of ongoing field operations, using small components that can be readily moved between
manufacturing facilities and field locations. Furthermore, for metallurgical considerations,
a wider selection of coatings and substrate materials are available for these devices
that may not be primary stress members of the oil and gas production operations system.
Coatings applied at elevated temperatures would incur additional manufacturing complexities
because such operations could adversely affect the heat treatment of such materials.
[0128] Additionally and alternatively, the design configuration of the downhole equipment
may be modified to facilitate the use of sleeves. For example, the orientation of
the tooljoints of a drillstring or workstring may optionally be altered such that
the externally-threaded pin connection is held at the surface during tool joint connection
operations, instead of the internally-threaded box connection. This reconfiguration
facilitates the use of sleeves because the sleeve does not fall down the hole or to
the ground when the connection is broken during pipe tripping operations. With this
design, there is no need for threading of the sleeve element as specified in
U. S. Patent 7,028,788 ("Wear Sleeve").
[0129] In one embodiment of the disclosure, the axis of the sleeve element may be substantially
parallel to the axis of the cylinder to which it is proximal. The sleeve element may
be free in one or more degrees of freedom or it may be fixed relative to the proximal
object (cylinder or body) using an appropriate attachment mechanism or geometric means
to provide restraint. Typically, the sleeve element would be constrained to move at
least axially with the proximal object, but it may be constrained or free in rotation.
The use of elliptical or non-circular cross-sections at the interface between the
sleeve and the proximal object would be one of several possible means to constrain
the sleeve to rotate with the proximal object. Furthermore, the sleeve element may
be inside or outside of the proximal object depending on the specific characteristics
and use of the sleeved oil and gas production device.
[0130] The sleeve may be made of any load bearing material such as metals, alloys, ceramics,
cermets, polymers, any type of steel (carbon steel, alloy steel, and any type of stainless
steel), WC based hard metals, and any of the combination of materials mentioned. The
sleeve material may be subject to local, lateral loads, but usually not to the typically
much larger axial loads experienced by the body that it is proximal to. Thus, the
sleeve material and geometry is not as limited by strength and toughness requirements
compared to the body. This allows selection of the material for the sleeve to be based
on, but not limited to, conditions such as the type of the coating and its processing
temperature.
[0131] Similar reconfigurations for other oil and gas production devices are feasible within
the scope of the disclosure to facilitate the use of sleeves which may be coated with
the materials that have been identified.
[0132] Disclosed herein are coated sleeved oil and gas well production devices and methods
of making and using such coated sleeved devices. The coatings described herein provide
significant performance improvement of the various oil and gas well devices and operations
disclosed herein. Figure 1 illustrates the overall oil and gas well production system,
for which the application of coatings to certain sleeved production devices as described
herein may provide improved performance of these devices. Figure 1A is a schematic
of a land based drilling rig 10. Figure 1B is a schematic of drilling rigs 10 drilling
directionally through sand 12, shale 14, and water 16 into oil fields 18. Figures
1C and 1D are schematics of producing wells 20 and injection wells 22. Figure 1E is
a schematic of a perforating gun 24. Figure IF is a schematic of gravel packing 26
and screen liner 28. With no loss of generality, different inventive coatings may
be preferred for different well production devices, and different types of sleeves
may be appropriate for different well production devices. A broad overview of production
operations in its entirety shows the extent of the possible field applications for
coated sleeve devices to mitigate friction, wear, erosion, corrosion, and deposits.
[0133] The method of coating such sleeved devices disclosed herein includes applying a suitable
coating to a portion of the inner sleeve surface, outer sleeve surface, or a combination
thereof that will be subject to friction, wear, corrosion, erosion, and/or deposits.
A coating is applied to at least a portion of the sleeve surface that is exposed to
contact with another solid or with a fluid flowstream, wherein: the coefficient of
friction of the coating is less than or equal to 0.15; the hardness of the coating
is greater than 400 VHN; the wear resistance of the coated sleeved device is at least
3 times that of the uncoated device; and/or the surface energy of the coating is less
than 1 J/m
2. There is art to choosing the appropriate coating from the disclosed coatings and
designing the appropriate sleeve element for the specific application to maximize
the technical and economic advantages of this technology.
[0135] A drill stem assembly is one example of a production device that may benefit from
the use of coatings. The geometry of an operating drill stem assembly is one example
of a class of applications comprising a cylindrical body. In the case of the drill
stem, the actual drill stem assembly is an inner cylinder that is in sliding contact
with the casing or open hole, an outer cylinder. These devices may have varying radii
and alternatively may be described as comprising multiple contiguous cylinders of
varying radii. As described below, there are several other instances of cylindrical
bodies in oil and gas well production operations, either in sliding contact due to
relative motion or stationary subject to contact by fluid flowstreams. The inventive
coatings may be used advantageously for each of these applications by considering
the relevant problem to be addressed, by evaluating the contact or flow problem to
be solved to mitigate friction, wear, corrosion, erosion, or deposits, and by judicious
consideration of how to design a sleeve into the device configuration and apply such
coatings to these sleeve elements for maximum utility and benefit to achieve an advantageous
coated sleeved oil and gas production device.
[0136] There are many more examples of oil and gas well production devices that provide
opportunities for beneficial use of coated sleeved devices, as described in the background,
including: stationary sleeved devices with coated sleeve elements for low friction
on initial installation, and for resistance to wear, corrosion and erosion, and resistance
to deposits on external or internal surfaces; and sleeved bearings, bushings, and
other geometries wherein the sleeve element is coated for friction and wear reduction
and resistance to corrosion and erosion.
[0137] In each case, there may be primary and secondary motivations for the use of coated
sleeved devices to mitigate friction, wear, corrosion, erosion, and deposits. The
same device may include more than one sleeve element with different coatings applied
to address different coatings design aspects, including the problem to be addressed,
the technology available for application of the coatings to the sleeve elements, and
the economics associated with each type of coating. There will likely be many tradeoffs
and compromises that govern the ultimate design of the sleeve element and selection
of the coating to be applied.
Overview of Use of Coated Sleeved Devices and Associated Benefits:
[0138] In the wide range of operations and equipment that are required during the various
stages of preparing for and producing hydrocarbons from a wellbore, there are several
prototypical applications that appear in various contexts. These applications may
be seen as various geometries of bodies in sliding mechanical contact and fluid flows
interacting with the surfaces of solid objects. The designs of these components may
be adapted to incorporate coated sleeve elements to reduce friction, wear, erosion,
corrosion, and deposits. In this sense, the components then become "coated sleeved
oil and gas well production devices." Several specific geometries and exemplary applications
are enumerated below, but a person skilled in the art will understand the broad scope
of the applications of coated sleeve devices and this list does not limit the range
of the inventive methods disclosed herein:
A. Coated Sleeved Cylindrical Bodies In Sliding Contact Due To Relative Motion:
[0139] In an application that is ubiquitous throughout production operations, two cylindrical
bodies are in contact, and friction and wear occur as one body moves relative to the
other. The bodies may be comprised of multiple cylindrical sections that are placed
contiguously with varying radii, and the cylinders may be placed coaxially or non-coaxially.
The component design may be adapted to place a sleeve element at the point of contact
between the two cylindrical bodies. This sleeve element may be coated on at least
a portion of the inner sleeve surface, outer sleeve surface, or some combination thereof
to beneficially reduce the contact friction and wear. The sleeve element may optionally
be removable and may be subsequently serviced or replaced, as necessary and appropriate
for the device application.
[0140] For example, devising a sleeve element for the tool joints of drill pipe or workstring
and coating such sleeve elements may be an effective means to utilize coatings to
reduce the contact friction between drill stem and casing or open-hole. For casing,
tubing, and sucker rod strings, the pipe coupling is a sleeve element that may have
coatings applied to a portion of the inner or outer surface area, or a combination
thereof. In yet another application, plunger-type artificial lift devices, it may
be advantageous to adapt the tool to have one or more coated sleeve elements comprising
the maximum outer diameter of the device to reduce wear and friction due to contact
with the tubing string.
An exemplary list of such applications is as follows:
[0141] Drill pipe may be picked up or slacked off causing longitudinal motion and may be
rotated within casing or open hole. Friction forces and device wear increase as the
well inclination increases, as the local wellbore curvature increases, and as the
contact loads increase. These friction loads cause significant drilling torque and
drag which must be overcome by the rig and drill string devices (see Figure 2). Figure
2A exhibits deflection occurring in a drill string assembly 30 in a directional or
horizontal well. Figure 2B is a schematic of a drill pipe 32 and a tool joint 34,
with threaded connection 35. A coated sleeve element 33 at the pin connection is illustrated
in this figure. Figure 2C is a schematic of a bit and bottom hole assembly 36. Figure
2D is a schematic of a casing 38 and a tool joint 39 to show the contact that occurs
between the two cylindrical bodies. Friction reducing coatings applied to sleeve elements
disclosed herein may be used to reduce the friction and wear between the two components
as the tool joint 39 rotates within the casing 38, also reducing the torque required
to turn the tool joint 39 for drilling lateral wells.
[0142] Bottomhole assembly (BHA) devices are located below the drill pipe on the drill stem
assembly and may be subjected to similar friction and wear, and thus the coatings
disclosed herein may provide a reduction in these mechanical problems (see Figure
3). In particular, the coatings disclosed herein applied to the BHA devices may reduce
friction and wear at contact points with the open hole and lengthen the tool life.
Low surface energy of the coatings disclosed herein may also inhibit sticking of formation
cuttings to the tools and corrosion and erosion limits may also be extended. It may
also reduce the tendency for differential sticking. Figure 3A is a schematic of mills
40 used in bottomhole assembly devices. Figure 3B is a schematic of a bit 41 and a
hole opener 42 used in bottomhole assembly devices. Figure 3C is a schematic of a
reamer 44 used in bottomhole assembly devices. Coated sleeve elements 43 are illustrated
in this figure. Figure 3D is a schematic of stabilizers 46 used in bottomhole assembly
devices. Figure 3E is a schematic of subs 48 used in bottomhole assembly devices.
[0143] Drill strings are operated within marine riser systems and may cause wear to the
riser as a result of the drilling operation. The vibrations of the riser due to ocean
currents may be mitigated by coatings, and marine growth may also be inhibited, further
reducing the drag associated with flowing currents. Referring to Figure 4, use of
the coatings disclosed herein on the riser pipe exterior 50 may be used to reduce
friction and vibrations due to ocean currents. In addition, the use of the coatings
disclosed herein on sleeved internal bushings 52 and other contact points which may
be protected by coated sleeved devices may be used to reduce friction and wear. Coated
sleeve elements 53 may be adapted to the riser connection and are illustrated in this
figure.
[0144] Plunger lifts remove water from a well by running up and down within a tubing string.
Both the plunger lift outer diameter and the tubing inner diameter may be affected
by wear, and the efficiency of the plunger lift decreases with wear and contact friction.
Reducing friction will increase the maximum allowable deviation for plunger lift operation
and increase the range of applicability of this technology. Reducing the wear of both
tubing and plunger lift will increase the time interval between required servicing.
From an operations perspective, reducing the wear of the tubing inner diameter is
highly desirable. Furthermore, coating the internal surface of a plunger lift may
be beneficial. Coated sleeve elements may be banded to the outside of the plunger
lift tool, wherein the outer diameter of the sleeve elements would be nearly equal
to the inner diameter of the tubing in which the device is operated, minus some tolerance
to allow the plunger to slide within the tubing string. Depending on the plunger lift
design, these sleeve elements could be replaced in the field and the tool returned
to service. Alternatively, the entire surface area of the plunger lift device could
be coated to reduce friction and wear. In the bypass state, fluid will flow through
the tool more easily if the flow resistance is reduced by coatings on the internal
portions of the tool, allowing the tool to drop faster.
[0145] Completion sliding sleeves may be moved axially, for example by stroking coiled tubing
to displace the cylindrical sleeve up or down relative to the tool body that may also
be cylindrical. These sleeves become susceptible to friction, wear, erosion, corrosion,
and sticking due to damage from formation materials and buildup of scale and deposits.
Coating portions of sleeve elements to enable movement within these sliding sleeve
systems will help to ensure that the sliding sleeve device will not stick when it
is required to be moved.
[0146] Sucker rods and Corod™ tubulars are used in pumping jacks to pump oil to the surface
in low pressure wells, and they may also be used to pump water out of gas wells. Friction
and wear occur continuously as the rods move relative to the tubing string. A reduction
in friction may enable selection of smaller pumping jacks and reduce the power requirements
for well pumping operations (see Figure 5). Referring to Figure 5A, the coated sleeves
disclosed herein may be used at the contact points of rod pumping devices, including,
but not limited to, the sucker rod coupling, which is a sleeve device attached to
the sucker rod 62, the sucker rod guide 60, the sucker rod 62, the tubing packer 64,
the downhole pump 66, and the perforations 68. Referring to Figure 5B, the coatings
disclosed herein may be used on polished rod clamp 70 and the polished rod 72 to provide
smooth durable surfaces as well as good seals. A coated sleeve element 71 is illustrated
at the sucker rod packoff to provide a low-friction tight seal. Figure 5C is a schematic
of a sucker rod 62 wherein the coatings disclosed herein may be used to prevent friction
and wear and on the threaded connections 74. A sucker rod coupling 73 may be coated
as a sleeve element in its own right, or it may be adapted for use with an external
coated sleeve, to provide a low-friction durable surface in contact with the tubing
string in which it reciprocates.
[0147] Sleeve devices in pistons and/or piston liners in pumps for drilling fluids on drilling
rigs and in pumps for stimulation fluids in well stimulation activities may be coated
to reduce friction and wear, enabling improved pump performance and longer device
life. Since certain equipment is used to pump acid, the coated sleeve liners may also
reduce corrosion and erosion damage to these devices.
[0148] Expandable tubulars are typically run in hole, supported with a hanging assembly,
and then expanded by running a mandrel through the pipe. Coating the surface of the
mandrel may greatly reduce the mandrel load and enable expandable tubular applications
in higher inclination wells or at higher expansion ratios than would otherwise be
possible. The mandrel may be configured to have coated sleeve devices at the locations
of highest contact stress. If removable, these coated sleeves would enable longer
mandrel tool life and possible redressing in the field. The speed and efficiency of
the expansion operation may be improved by significant friction reduction. The mandrel
is a tapered cylinder and may be considered to be comprised of contiguous cylinders
of varying radii; alternatively, a tapered mandrel may be considered to have a complex
geometry.
[0149] Control lines and conduits may be internally coated for reduced flow resistance and
corrosion / erosion benefits. Glass filament fibers may be pumped down internally
coated conduits and turnaround subs with reduced resistance.
[0150] Tools operated in wellbores are typically cylindrical bodies or bodies comprised
of contiguous cylinders of varying radii that are operated in casing, tubing, and
open hole, either on wireline or rigid pipe. Friction resistance increases as the
wellbore inclination increases or local wellbore curvature increases, rendering operation
of such tools to be unreliable on wireline. Coated sleeve devices at the contact surfaces
may enable such tools to be reliably operated on wireline at higher inclinations or
reduce the force to push tools down a horizontal well using coiled tubing, tractors,
or pump-down devices. A list of such tools includes but is not limited to: logging
tools, perforating guns, and packers (see Figure 6). Referring to Figure 6A, the coatings
disclosed herein may be used on the external surfaces of a caliper logging tool 80
to reduce friction and wear with the open hole 82 or casing (not shown). The components
with maximum diameter 83 may be sleeved with low-friction coating sleeves to enable
the tool to run in hole with less resistance and wear. Referring to Figure 6B, the
coatings disclosed herein may be used on the external sleeved surfaces 85 of an acoustic
logging sonde 84, including, but not limited to, the signal transmitter 86 and signal
receiver 88 to reduce friction and wear with the casing 90 or in open hole. Referring
to Figures 6C and 6D, the coatings disclosed herein may be used on the external coated
sleeved surfaces 93 of packer tools 92 and on sleeves 95 of perforating gun 94 to
reduce friction and wear with the open hole. Low surface energy of the coatings will
inhibit sticking of formation to the tools, and corrosion and erosion limits may also
be extended.
[0151] Wireline is a slender cylindrical body that is operated within casing, tubing, and
open hole. At a higher level of detail, each strand is a cylinder, and the twisted
strands are a bundle of non-coaxial cylinders that together comprise the effective
cylinder of the wireline. Friction forces are present at the contact points between
wireline and wellbore, and therefore coating the wireline with low-friction coatings
will enable operation with reduced friction and wear. Braided line, multi-conductor,
single conductor, and slickline may all be beneficially coated with low-friction coatings
(see Figure 7). Referring to Figure 7A, the coatings disclosed herein may be applied
to the wire line 100 by application to the wire 102, the individual strands of wire
104 or to the bundle of strands 106. A pulley type device 108 as seen in Figure 7B
may be used to run logging tools conveyed by wireline 100 into casing, tubing and
open hole. The pulley device may use coated sleeves advantageously in the areas of
the pulley and bearings that are subject to load and wear due to friction.
[0152] Casing centralizers and contact rings for downhole tools are sleeve devices that
may be coated to reduce the friction resistance of placing these devices in a wellbore
and providing movement downhole, particularly in high wellbore inclination angles.
B. Coated Cylindrical Bodies That Are Primarily Stationary:
[0153] There are diverse applications for coating sleeved portions of the exterior, interior,
or both of cylindrical bodies (e.g., pipe or modified pipe), primarily for erosion,
corrosion, and wear resistance, but also for friction reduction of fluid flow. The
cylindrical bodies may be coaxial, contiguous, non-coaxial, non-contiguous or any
combination thereof, with sleeves in proximal location to the inner or outer surface
of a cylindrical body. In these applications, the coated sleeved cylindrical device
may be essentially stationary for long periods of time, although perhaps a secondary
benefit or application of the coated sleeve is to reduce friction loads when the production
device is installed.
An exemplary list of such applications is as follows:
[0154] Perforated basepipe, slotted basepipe, or screen basepipe for sand control are often
subject to erosion and corrosion damage during the completion and stimulation treatment
(e.g., gravel pack or frac pack treatment) and during the well productive life. For
example, a coating obtained with the inventive method will provide greater inner diameter
for the flow and reduce the flowing pressure drop relative to thicker plastic coatings.
In another example, corrosive produced fluids may attack materials and cause material
loss over time. Furthermore, highly productive formation intervals may provide fluid
velocities that are sufficiently high to cause erosion. These fluids may also carry
solid particles, such as fines or formation sand with a tendency to fail the completion
device. It is further possible for deposits of asphaltenes, paraffins, scale, and
hydrates to form on the completion equipment such as basepipes. Coatings can provide
benefits in these situations by reducing the effects of friction, wear, corrosion,
erosion, and deposits. (See Figure 8.) Certain coatings for screen applications have
been disclosed in
U.S. Patent No. 6,742,586 B2. The use of coated sleeved devices in this application facilitates installation of
the sand control device due to reduced friction and wear. Coated sleeved devices may
also be used as "blast joints" where high sand and proppant particle velocities may
be expected to reduce the useful life of the sand screen material.
[0155] Wash pipes, shunt tubes, and service tools used in gravel pack operations may be
coated internally, externally, or both to reduce erosion and flow resistance. Fluids
with entrained solids for the gravel pack are pumped at high rates through these devices.
Sleeved devices may be used at specific locations in these tools to protect the main
body of the device from erosion due to sand and proppant flow.
[0156] Blast joints may be advantageously coated for greater resistance to erosion resulting
from impingement of fluids and solids at high velocity. Coated sleeved devices may
be used advantageously on blast joints at the specific locations where the greatest
amount of wear damage may be expected.
[0157] Thin metal meshes may be coated for friction reduction and resistance to corrosion
and erosion. The coating process may be applied to individual cylindrical strands
prior to weaving or to the collective mesh after the weave has been performed, or
both, or in combination. A screen may be considered to be comprised of many cylinders.
Wire strands may be drawn through a coating device to enable coating application of
the entire surface area of the wire. The coating applications include but are not
limited to: sand screens disposed within completion intervals, Mazeflo™ completion
screens, sintered screens, wirewrap screens, shaker screens for solids control, and
other screens used as oil and gas well production devices. The coating can be applied
to at least a portion of filtering media, screen basepipe, or both. (See Figure 8.)
Figure 8 depicts exemplary application of the coatings disclosed herein on screens
and basepipe. In particular, the coatings disclosed herein may be applied to the slotted
liner of screens 110 as well as basepipe 112 as shown in Figures 8A and 8B to prevent
erosion, corrosion, and deposits thereon. The detailed closeup of Figure 8A shows
coated sleeve element 111 external to the screen to allow it to slide downhole with
reduced friction resistance. The coatings disclosed herein may also be applied to
screens in the shale shaker 114 of solids control equipment as shown in Figure 8C.
Coated sleeved devices may be used in a variety of ways with these devices as described
above, to reduce friction at the wellbore contact during installation and to reduce
erosion damage due to sand and proppant flow during stimulation and production at
specific locations where the sleeve is applied.
[0158] Coated sleeve devices may reduce material hardness requirements and mitigate the
effects of corrosion and erosion for certain devices and components, enabling lower
cost materials to be used as substitute for stellite, tungsten carbide, MP35N, high
alloy materials, and other costly materials selected for this purpose.
C. Plates. Disks. And Complex Geometries:
[0159] There are many coated sleeve device applications that may be considered for non-cylindrical
devices such as plates and disks or for more complex geometries. One exemplary application
of a disk geometry is a washer device that may be coated on one or both sides to reduce
friction during operation of the device. The benefits of coatings may be derived from
a reduction in sliding contact friction and wear resulting from relative motion with
respect to other devices, or perhaps a reduction in erosion, corrosion, and deposits
from the interaction with fluid streams, or in many cases by a combination of both.
These applications may benefit from the use of coatings as described below.
An exemplary list of such applications is as follows:
[0160] Chokes, valves, valve seats, seals, ball valves, inflow control devices, smart well
valves, and annular isolation valves may beneficially use coated parts such as sleeves
and washers to reduce friction, erosion, corrosion, and damage due to deposits. Many
of these devices are used in wellhead equipment (see Figures 9 and 10). In particular,
referring to Figures 9A, 9B, 9C, 9D and 9E, valves 113, blowout preventers 115, wellheads
114, lower Kelly cocks 116, and gas lift valves 118 may use coated sleeves and washers
117 with the coatings disclosed herein to provide resistance to friction, erosion,
and corrosion in high velocity components, and the smooth surfaces of these coated
devices provides enhanced sealability. In Figure 9E, coated sleeves 119 may be used
to ease entry of the gas lift device into the side pocket and to seal properly. In
addition, referring to Figures 10A, 10B and 10C, chokes 120, orifice meters 122, and
turbine meters 124 may have flow restrictions and other components (i.e. impellers
and rotors) that use coated sleeves and washers 123 with the coatings disclosed herein
to provide further resistance to friction, erosion, and corrosion. Other surface areas
of the same production device may be protected by coated sleeves and washers for reduced
friction and wear by using the same or different coating on a different portion of
the production device.
[0161] Seats, nipples, valves, sidepockets, mandrels, packer slips, packer latches, etc.
may beneficially use coated sleeve and washer devices with low-friction coatings.
[0162] Subsurface safety valves are used to control flow in the event of possible loss of
containment at the surface. These valves are routinely used in offshore wells to increase
operational integrity and are often required by regulation. Improvements in the reliability
and effectiveness of subsurface safety valves provide substantial benefits to operational
integrity and may avoid a costly workover operation in the event that a valve fails
a test. Enhanced sealability, resistance to erosion, corrosion, and deposits, and
reduced friction and wear in moving valve devices may be highly beneficial for these
reasons. The use of coated sleeves and washers in subsurface safety valves will enhance
their operability and obtain the benefits described above.
[0163] Gas lift and chemical injection valves are commonly used in tubing strings to enable
injection of fluids, and coating portions of these devices will improve their performance.
Gas lift is used to reduce the hydrostatic head and increase flow from a well, and
chemicals are injected, for example, to inhibit formation of hydrates or scale in
the well that would impede flow. The use of coated sleeves and washers in gas lift
and chemical injection valves will enhance their operability and obtain the benefits
described above.
[0164] Elbows, tees, and couplings may be internally coated for fluid flow friction reduction
and the prevention of buildup of scale and deposits. Coated sleeve devices may be
used in these applications at specific locations of high erosion, such as at bends,
unions, tees, and other areas of fluid mixing and wall impingement of entrained solids.
[0165] The ball bearings, sleeve bearings, or journal bearings of rotating equipment may
be coated to provide low friction and wear resistance, and to enable longer life of
the bearing devices.
[0166] Wear bushings may utilize coated sleeve devices for reduced friction and wear, and
for enhanced operability.
[0167] Coated sleeves in dynamic metal-to-metal seals may be used to enhance or replace
elastomers in reciprocating and/or rotating seal assemblies.
[0168] Moyno™ and progressive cavity pumps comprise a vaned rotor turning within a fixed
stator. Coated sleeve devices in these components will enable improved operation and
increase the pump efficiency and durability.
[0169] Impellers and stators in rotating pump equipment may incorporate coated sleeve devices
for erosion and wear resistance, and for durability where fine solids may be present
in the flowstream. Such applications include submersible pumps.
[0170] Coated sleeve devices in a centrifuge device for drilling fluids solids control enhance
the effectiveness of these devices by preventing plugging of the centrifuge discharge.
The service life of the centrifuge may be extended by the erosion resistance provided
by coated sleeve elements.
[0171] Springs in tools that are coated may have reduced contact friction and long service
life reliability. Examples include safety valves, gas lift valves, shock subs, and
jars.
[0172] Logging tool devices may use coated sleeve devices to improve operations involving
deployment of arms, coring tubes, fluid sampling flasks, and other devices into the
wellbore. Devices that are extended from and then retracted back into the tool may
be less susceptible to jamming due to friction and solid deposits if coatings are
applied.
[0173] Fishing equipment, including but not limited to, washover pipe, grapple, and overshot,
may beneficially use coated sleeves to facilitate latching onto and removing a disconnected
piece of equipment, or "fish," from the wellbore. Low friction entry into the washover
pipe may be facilitated by an internal coated sleeve, and a hard coating on the grapple
sleeve may improve the bite of the tool. (See Figure 11.) In particular, referring
to Figure 11A, the coatings disclosed herein may be applied to washover pipe 130,
washover pipe connector sleeves 132, rotary shoes 134, and fishing devices to reduce
friction of entry of fish 136 into the washover string. Tapered and coated sleeve
133 may be used to ease the fish into the washpipe. In addition, referring to Figure
11B, the coatings disclosed herein may be applied to grapple sleeves 138 to maintain
material hardness for good grip.
D. Threaded Connections:
[0174] High strength pipe materials and special alloys in oilfield applications may be susceptible
to galling, and threaded connections may be beneficially coated so as to reduce friction
and increase surface hardness during connection makeup and to enable reuse of pipe
and connections without redressing the threads. Seal performance may be improved by
enabling higher contact stresses without risk of galling.
[0175] Pin and/or box threads of casing, tubing, drill pipe, drill collars, work strings,
surface flowlines, stimulation treatment lines, threads used to connect downhole tools,
marine risers, and other threaded connections involved in production operations may
be beneficially coated with the low-friction coatings disclosed herein. Threads may
be coated separately or in combination with current technology for improved connection
makeup and galling resistance, including shot-peening and cold-rolling, and possibly
but less likely, chemical treatments of the threads. (See Figure 12.) Referring to
Figure 12A, the pin 150 and/or box 152 may be coated with the coatings disclosed herein.
Referring to Figure 12B, the threads 154 and/or shoulder 156 may be coated with the
coatings disclosed herein. Coated sleeve elements 153 are illustrated at the connection
pin. In Figure 12C, the threaded connections (not shown) of threaded tubulars 158
may be coated with the coatings disclosed herein. In Figure 12D, galling 159 of the
threads 154 may be prevented by use of the coatings disclosed herein. Coatings in
this instance could be applied to one or both sets of threads of a threaded connection.
E. Exemplary Sleeve Configuration for Drilling Application
[0176] When the drill string is extended or shortened during the drilling process, pieces
of drill pipe are screwed together and unscrewed. Some modern drilling rigs use automated
equipment for this operation, which is known as "making a connection." As shown in
Figure 13A, the slips 171 are set in the drill rig floor or rotary table 173 to hold
the drill string 175, the pipe is unscrewed, and the connection is "broken." The detached
pipe held by the rig elevators can be added to the string if running pipe in the hole,
or removed if tripping pipe out of the hole. In Figure 13A, the connection 177 held
by the slips is the tool joint box connection.
[0177] Figure 13B shows a coated sleeve element 181 on the pin 179 of a connection that
is oriented according to the standard "pin-down" convention. Note that the gravity
vector 180 points downwards. It may be appreciated that this is inconvenient in the
sense that when the connection is broken and the separated pipe is removed, the sleeve
will fall to the ground or down the hole if not somehow attached. In
U.S. Patent 7,028,788, Strand resolved this problem by threading the sleeve and the pin connection so that
the sleeve stays with the pin during connection makes and breaks.
[0178] It may be appreciated that there may be some problems with a threaded sleeve system
in that, during the drilling process, the threads specified in
U.S. Patent 7,028,788 are exposed to the outside of the drill pipe and are in proximity to the formation
and drilling fluids. The potential for these threads to be damaged or to have formation
material packed in the threads would appear to be significant. Additionally, there
will be extra costs associated with the manufacture and maintenance of the threads
on both sleeve and pin. If the threads of the sleeve or pin connection are damaged,
the corresponding piece of equipment must be repaired prior to subsequent use.
[0179] One exemplary alternative method is to use the "pin-up" configuration as shown in
Figure 13C. With the pin 179 facing up, the sleeve 181 may be placed over the pin
directly when making the connection, and on breaking the connection the sleeve remains
in place. Again, the gravity vector 180 points down in this figure. Optionally, if
it is desired to prevent the sleeve from rotating freely relative to the drill pipe
and if no alternative means of attaching the sleeve is used, then one means to prevent
the sleeve from rotating is to use a key or slot, or perhaps provide an elliptically
profiled inner sleeve surface area and corresponding cross-section area for the sleeve
on the pin connection.
[0180] Figure 13D illustrates an exaggerated view of the elliptical sleeve inner profile
configuration. The outer sleeve surface 183 has a circular cross-section, as does
the inner surface 188 of the pin connection. The pin threads are made on a tapered
conical section as usual. However, in the lower-stress area of the pin above the threads,
an elliptical cross-section 186 is machined to match the dimensions of the sleeve
inner surface cross-section 184, with suitable tolerances to allow for slipping the
sleeve over the threads onto the pin body. Careful analysis is required to ensure
that there is sufficient material strength in the sleeve so that, with the expected
torsional loads, it does not deform, and that the strength of the pin has not been
compromised. Typically, material may be removed up to the bevel diameter without affecting
pin strength. Recognizing that the pipe will be turned in one direction, an asymmetric
profile may be considered, and other alternative cross-sectional profiles may be devised
without departing from the spirit of the disclosure.
[0181] Alternative means of attaching sleeves to tool joints, using the pin connection,
box connection, or other proximal areas of the drill pipe may be conceived, without
departing from the basic concept of using coated sleeve elements to utilize advantageous
low-friction materials while drilling.
Drilling Conditions. Application, and Benefits
[0182] A detailed examination of one important aspect of production operations, the drilling
process, can help to identify several challenges and opportunities for the beneficial
use of a specific application of coated sleeved devices in the well production process.
[0183] Deep wells for the exploration and production of oil and gas are drilled with a rotary
drilling system which creates a borehole by means of a rock cutting tool, a drill
bit. The torque driving the bit is often generated at the surface by a motor with
mechanical transmission box. Via the transmission, the motor drives the rotary table
or top drive unit. The medium to transport the energy from the surface to the drill
bit is a drill string, mainly consisting of drill pipes. The lowest part of the drill
string is the bottom hole assembly (abbreviated herein as BHA) consisting of bit,
drill collars, stabilizers, measurement tools, under-reamers, motors, and other devices
known to those skilled in the art. The combination of the drill string and the bottom
hole assembly is referred to herein as a drill stem assembly. Alternatively, coiled
tubing may replace the drill string, and the combination of coiled tubing and the
bottom hole assembly is also referred to herein as a drill stem assembly. In still
another configuration, cutting elements proximal to the bottom end of the casing comprise
a "casing-while-drilling" system. The coated sleeved oil and gas well production devices
disclosed herein provide particular benefit in such downhole drilling operations.
[0184] With today's advanced directional drilling technology, multiple lateral wellbores
may be drilled from the same starter wellbore. This may mean drilling over far longer
depths and the use of directional drilling technology, e.g., through the use of rotary
steerable systems (abbreviated herein as RSS). Although this gives major cost and
logistical advantages, it also greatly increases wear on the drill string and casing.
In some cases of directional or extended reach drilling, the degree of vertical deflection,
inclination (angle from the vertical), can be as great as 90°, which are commonly
referred to as horizontal wells. In drilling operations, the drill string assembly
has a tendency to rest against the side wall of the borehole or the well casing. This
tendency is much greater in directional wells due to the effect of gravity. As the
drill string increases in length and/or degree of deflection, the overall frictional
drag created by rotating the drill string also increases. To overcome this increase
in frictional drag, additional power is required to rotate the drill string. The resultant
friction and wear impact the drilling efficiency. The measured depth that can be achieved
in these situations may be limited by the available torque capacity of the drilling
rig and the torsional strength of the drill string. There is a need to find more efficient
solutions to extend equipment lifetime and drilling capabilities with existing rigs
and drive mechanisms to extend the lateral reach of these operations.
[0185] The deep drilling environment, especially in hard rock formations, induces severe
vibrations in the drill stem assembly, which can cause reduced drill bit rate of penetration
and premature failure of the equipment downhole. The drill stem assembly vibrates
axially, torsionally, laterally or usually with a combination of these three basic
modes, that is, coupled vibrations. The use of coated sleeve devices disclosed herein
may reduce the required torque for drilling and also provide resistance to torsional
vibration instability, including stick-slip vibration dysfunction of the drill string
and bottom hole assembly. Reduced drill string torque may allow the drilling operator
to drill wells at higher rate of penetration (ROP) than when using conventional drilling
equipment. Coated sleeved devices in the drill string as disclosed herein may prevent
or delay the onset of drill string buckling, including helical buckling, and may prevent
vibration-related drill stem assembly failures and the associated non-productive time
during drilling operations.
[0186] The drill string includes one or more devices chosen from drill pipe, tool joints,
transition pipe between the drill string and bottom hole assembly including tool joints,
heavy weight drill pipe including tool joints and wear pads, and combinations thereof.
The bottom hole assembly includes one or more devices chosen from, but not limited
to: stabilizers, variable-gauge stabilizers, back reamers, drill collars, flex drill
collars, rotary steerable tools, roller reamers, shock subs, mud motors, logging while
drilling (LWD) tools, measuring while drilling (MWD) tools, coring tools, under-reamers,
hole openers, centralizers, turbines, bent housings, bent motors, drilling jars, acceleration
jars, crossover subs, bumper jars, torque reduction tools, float subs, fishing tools,
fishing jars, washover pipe, logging tools, survey tool subs, nonmagnetic counterparts
of any of these devices, and combinations thereof and their associated external connections.
[0187] The coated sleeved oil and gas well production devices disclosed herein may be used
in drill stem assemblies with downhole temperature ranging from -7 to 204°C (20 to
400°F) with a lower limit of -7, 4, 16, 27, or 38°C (20, 40, 60, 80, or 100°F), and
an upper limit of 66, 93, 121, 149, 177 or 204°C (150, 200, 250, 300, 350 or 400°F).
During rotary drilling operations, the drilling rotary speeds at the surface may range
from 0 to 200 RPM with a lower limit of 0, 10, 20, 30, 40, or 50 RPM and an upper
limit of 100, 120, 140, 160, 180, or 200 RPM. In addition, during rotary drilling
operations, the drilling mud pressure may range from 96 kPa (14 psi) to 137.895 MPa
(20,000 psi) with a lower limit of 96, 689, 1379, 2068, 2758, 3447 or 6895 kPa (14,
100, 200, 300, 400, 500, or 1000 psi), and an upper limit of 34.474, 68.948, 103.421
or 137.895 MPa (5000, 10000, 15000, or 20000 psi).
[0188] In one form, the coated sleeved oil and gas well production devices disclosed herein
with the coating on at least a portion of the exposed outer surface provides at least
2 times, or 3 times, or 4 times, or 5 times greater wear resistance than an uncoated
device. Additionally, the coated sleeved oil and gas well production device disclosed
herein when used on a drill stem assembly with the coating on at least a portion of
the surface provides reduction in casing wear as compared to when an uncoated drill
stem assembly is used for rotary drilling. Moreover, the coated sleeved oil and gas
well production devices disclosed herein when used on a drill stem assembly with the
coating on at least a portion of the surface reduces casing wear by at least 2 times,
or 3 times, or 4 times, or 5 times versus the use of an uncoated drill stem assembly
for rotary drilling operations.
[0189] The coatings on drill stem assemblies disclosed herein may also eliminate or reduce
velocity weakening of the friction coefficient. More particularly, rotary drilling
systems used to drill deep boreholes for hydrocarbon exploration and production often
experience severe torsional vibrations leading to instabilities referred to as "stick-slip"
vibrations, characterized by (i) sticking phases where the bit or BHA slows down until
it stops (relative sliding velocity is zero), and (ii) slipping phases where the relative
sliding velocity of the downhole assembly rapidly accelerates to a value much larger
than the rotary speed (RPM) imposed by the drilling rig at the surface. This problem
is particularly acute with drag bits, which consist of fixed blades or cutters mounted
on the surface of a bit body. Non-linearities in the constitutive laws of friction
lead to the instability of steady frictional sliding against stick-slip oscillations.
Therefore, this leads to a complex problem.
[0190] Velocity weakening behavior, which is indicated by a decreasing coefficient of friction
with increasing relative sliding velocity, may cause torsional instability triggering
stick-slip vibrations. Sliding instability is an issue in drilling since it is one
of the primary founders which limits the maximum rate of penetration. In drilling
applications, it is advantageous to avoid the stick-slip condition because it leads
to vibrations and wear, including the initiation of damaging coupled vibrations. By
reducing or eliminating the velocity weakening behavior, the coatings on drill string
assemblies disclosed herein bring the system into the continuous sliding state, where
the relative sliding velocity is constant and does not oscillate (avoidance of stick-slip)
or display violent accelerations or decelerations in localized RPM. Even with the
prior art method of avoiding stick-slip motion with the use of a lubricant additive
or pills to drilling muds, at high normal loads and small sliding velocities stick-slip
motion may still occur. The coatings on drill stem assemblies disclosed herein may
provide for no stick-slip motion even at high normal loads.
[0191] In intervals that contain mostly shale formations, another drilling problem is common.
"Bit balling" may occur when shale cuttings stick to the bit cutting face by differential
fluid pressure, reducing drilling efficiencies and ROP significantly. Sticking of
shale cuttings to BHA devices such as stabilizers leads to drilling inefficiencies.
These problems are exacerbated by the use of water-based drilling fluids, which may
be preferred for both cost and environmental reasons.
[0192] Drilling vibrations and bit balling are two of the most common causes of drilling
inefficiencies. These inefficiencies can manifest themselves as ROP limiters or "founder
points" in the sense that the ROP does not increase linearly with weight on bit (abbreviated
herein as WOB) and revolutions per minute (abbreviated herein as RPM) of the bit as
predicted from bit mechanics. This limitation is depicted schematically in Figure
14. It has been recognized in the drilling industry that drill stem vibrations and
bit balling are two of the most challenging rate of penetration limiters. The coated
sleeved devices disclosed herein may be applied to the drill stem assembly to help
mitigate these ROP limitations.
[0193] Additionally, coated sleeved devices will improve the performance of drilling tools,
particularly a bottom hole assembly, for drilling in formations containing clay and
similar substances. These coating materials provide thermodynamically low energy surfaces,
e.g., non-water wetting surface for bottom hole devices. The coatings disclosed herein
are suitable for oil and gas drilling in gumbo-prone areas, such as in deep shale
drilling with high clay content, using water-based muds (abbreviated herein as WBM)
to prevent bottom hole assembly balling.
[0194] Furthermore, the coated sleeved devices disclosed herein when applied to the drill
string assembly can simultaneously reduce contact friction, balling and reduce wear
while not compromising the durability and mechanical integrity of casing. Thus, the
coated sleeved devices disclosed herein are "casing friendly" in that they do not
degrade the life or functionality of the casing. The coatings disclosed herein are
characterized by low or no sensitivity to velocity weakening friction behavior. Thus,
the drill stem assemblies provided with the coated sleeved devices disclosed herein
provide low friction surfaces with advantages in both mitigating stick-slip vibrations
and reducing parasitic torque to further enable ultra-extended reach drilling.
[0195] The coated sleeved devices disclosed herein for drill stem assemblies provide for
the following exemplary non-limiting advantages: i) mitigating stick-slip vibrations,
ii) reducing torque and drag for extending the reach of extended reach wells and iii)
mitigating drill bit and other bottom hole assembly balling. These advantages, together
with minimizing parasitic torque, may lead to significant improvements in drilling
rate of penetration as well as durability of downhole drilling equipment, thereby
also contributing to reduced non-productive time (abbreviated herein as NPT). The
coatings disclosed herein not only reduce friction, but also withstand the aggressive
downhole drilling environments requiring chemical stability, corrosion resistance,
impact resistance, durability against wear, erosion and mechanical integrity (coating-substrate
interface strength). The coatings disclosed herein are also amenable for application
to complex geometries without damaging the substrate properties. Moreover, the coatings
disclosed herein also provide low energy surfaces necessary to provide resistance
to balling of bottom hole devices.
Exemplary Coated Sleeved Device Embodiments:
[0196] The discussion of the drilling process has focused on the friction and wear benefits
of the coated sleeved devices, with primary application to cylinders in sliding contact,
and it has also identified the benefits of low energy surfaces for reduced sticking
of formation cuttings to bottom hole devices. These same technical discussions pertain
to other instances of cylinders in sliding contact due to relative motion which may
be adapted to use coated sleeved devices, with modified circumstances accordingly.
[0197] Friction and wear reduction are primary motivations for the application of coatings
to bodies in sliding contact due to relative motion. For stationary devices, the incentives
and benefits of coatings may be slightly different. Although friction and wear may
be important secondary factors (for instance in the initial installation of the device),
the primary benefit of coated sleeved devices may be their resistance to erosion,
corrosion, and deposits, more akin to the problem of reducing the adhesion of shale
formations to the BHA, and these factors then become major dimensions in their selection
and use.
[0198] In one exemplary embodiment, a coated sleeved oil and gas well production device
comprises an oil and gas well production device including one or more cylindrical
bodies, one or more sleeves proximal to the outer diameter or the inner diameter of
the one or more cylindrical bodies, and a coating on at least a portion of the inner
sleeve surface, the outer sleeve surface, or a combination thereof of the one or more
sleeves, wherein the coating is chosen from an amorphous alloy, a heat-treated electroless
or electro plated nickel-phosphorous based composite with a phosphorous content greater
than 12 wt%, graphite, MoS
2, WS
2, a fullerene based composite, a boride based cermet, a quasicrystalline material,
a diamond based material, diamond-like-carbon (DLC), boron nitride, and combinations
thereof.
[0199] In another exemplary embodiment, the coated oil and gas well production device comprises
an oil and gas well production device including one or more bodies with the proviso
that the one or more bodies does not include a drill bit, one or more sleeves proximal
to the outer surface or the inner surface of the one or more bodies, and a coating
on at least a portion of the inner sleeve surface, the outer sleeve surface, or a
combination thereof of the one or more sleeves, wherein the coating is chosen from
an amorphous alloy, a heat-treated electroless or electro plated nickel-phosphorous
composite with a phosphorous content greater than 12 wt%, graphite, MoS
2, WS
2, a fullerene based composite, a boride based cermet, a quasicrystalline material,
a diamond based material, diamond-like-carbon (DLC), boron nitride, and combinations
thereof.
[0200] The coefficient of friction of the coating may be less than or equal to 0.15, or
0.13, or 0.11, or 0.09 or 0.07 or 0.05. The friction force may be calculated as follows:
Friction Force = Normal Force x Coefficient of Friction. In another form, the coated
oil and gas well production device may have a dynamic friction coefficient of the
coating that is not lower than 50%, or 60%, or 70%, or 80% or 90% of the static friction
coefficient of the coating. In yet another form, the coated sleeved oil and gas well
production device may have a dynamic friction coefficient of the coating that is greater
than or equal to the static friction coefficient of the coating.
[0201] The coated sleeved oil and gas well production device may be fabricated from iron
based steels, Al-base alloys, Ni-base alloys and Ti-base alloys. 4142 type steel is
one non-limiting exemplary iron based steel used for sleeved oil and gas well production
devices. The surface of the iron based steel substrate may be optionally subjected
to an advanced surface treatment prior to coating application. The advanced surface
treatment may provide one or more of the following benefits: extended durability,
enhanced wear, reduced friction coefficient, enhanced fatigue and extended corrosion
performance of the coating layer(s). Non-limited exemplary advanced surface treatments
include ion implantation, nitriding, carburizing, shot peening, laser and electron
beam glazing, laser shock peening, and combinations thereof. Such surface treatments
may harden the substrate surface by introducing additional species and/or introduce
deep compressive residual stress resulting in inhibition of the crack growth induced
by fatigue, impact and wear damage.
[0202] The coating disclosed herein for coated sleeved devices may be chosen from an amorphous
alloy, electroless and/or electro plating nickel-phosphorous based composite, graphite,
MoS
2, WS
2, a fullerene based composite, a boride based cermet, a quasicrystalline material,
a diamond based material, diamond-like-carbon (DLC), boron nitride, and combinations
thereof. The diamond based material may be chemical vapor deposited (CVD) diamond
or polycrystalline diamond compact (PDC). In one advantageous embodiment, the coated
oil and gas well production device is coated with a diamond-like-carbon (DLC) coating,
and more particularly the DLC coating may be chosen from tetrahedral amorphous carbon
(ta-C), tetrahedral amorphous hydrogenated carbon (ta-C:H), diamond-like hydrogenated
carbon (DLCH), polymer-like hydrogenated carbon (PLCH), graphite-like hydrogenated
carbon (GLCH), silicon containing diamond-like-carbon (Si-DLC), metal containing diamond-like-carbon
(Me-DLC), oxygen containing diamond-like-carbon (O-DLC), nitrogen containing diamond-like-carbon
(N-DLC), boron containing diamond-like-carbon (B-DLC), fluorinated diamond-like-carbon
(F-DLC) and combinations thereof.
[0203] Significantly decreasing the coefficient of friction (COF) of the coated sleeved
oil and gas well production device will result in a significant decrease in the friction
force. This translates to a smaller force required to slide the cuttings along the
surface when the device is a coated drill stem assembly. If the friction force is
low enough, it may be possible to increase the mobility of cuttings along the surface
until they can be lifted off the surface of the drill stem assembly or transported
to the annulus. It is also possible that the increased mobility of the cuttings along
the surface may inhibit the formation of differentially stuck cuttings due to the
differential pressure between mud and mud-squeezed cuttings-cutter interface region
holding the cutting onto the cutter face. Lowering the COF on oil and gas well production
device surfaces is accomplished by coating these surfaces with coatings disclosed
herein. These coatings applied to the oil and gas well production device are able
to withstand the aggressive environments of drilling including resistance to erosion,
corrosion, impact loading, and exposure to high temperatures.
[0204] In addition to low COF, the coatings of the present disclosure are also of sufficiently
high hardness to provide durability against wear during oil and gas well production
operations. More particularly, the Vickers hardness or the equivalent Vickers hardness
of the coatings on the oil and gas well production device disclosed herein may be
greater than or equal to 400, 500, 600, 700, 800, 900, 1000, 1500, 2000, 2500, 3000,
3500, 4000, 4500, 5000, 5500, or 6000. A Vickers hardness of greater than 400 allows
for the coated oil and gas well production device when used as a drill stem assembly
to be used for drilling in shales with water based muds and the use of spiral stabilizers.
Spiral stabilizers have less tendency to cause BHA vibrations than straight-bladed
stabilizers. Figure 15 depicts the relationship between coating COF and coating hardness
for some of the coatings disclosed herein relative to the prior art drill string and
BHA steels. The combination of low COF and high hardness for the coatings disclosed
herein when used as a surface coating on the drill stem assemblies provides for hard,
low COF durable materials for downhole drilling applications.
[0205] The coated sleeved oil and gas well production devices with the coatings disclosed
herein also provide a surface energy less than 1, 0.9, 0.8, 0.7, 0.6, 0.5, 0.4, 0.3,
0.2, or 0.1 J/m
2. In subterraneous rotary drilling operations, this helps to mitigate sticking or
balling by rock cuttings. Contact angle may also be used to quantify the surface energy
of the coatings on the coated sleeved oil and gas well production devices disclosed
herein. The water contact angle of the coatings disclosed herein is greater than 50,
60, 70, 80, or 90 degrees.
[0206] Further details regarding the coatings disclosed herein for use in coated sleeved
oil and gas well production devices are as follows:
Amorphous Alloys:
[0207] Amorphous alloys as coatings for coated sleeved oil and gas well production devices
disclosed herein provide high elastic limit/ flow strength with relatively high hardness.
These attributes allow these materials, when subjected to stress or strain, to stay
elastic for higher strains/ stresses as compared to the crystalline materials such
as the steels used in drill stem assemblies. The stress-strain relationship between
the amorphous alloys as coatings for drill stem assemblies and conventional crystalline
alloys/ steels is depicted in Figure 16, and shows that conventional crystalline alloys/
steels can easily transition into plastic deformation at relatively low strains/ stresses
in comparison to amorphous alloys. Premature plastic deformation at the contacting
surfaces leads to surface asperity generation and the consequent high asperity contact
forces and COF in crystalline metals. The high elastic limit of amorphous metallic
alloys or amorphous materials in general can reduce the formation of asperities resulting
also in significant enhancement of wear resistance. Amorphous alloys as coatings for
sleeved oil and gas well production devices would result in reduced asperity formation
during production operations and thereby reduced COF of the device.
[0208] Amorphous alloys as coatings for sleeved oil and gas well production devices may
be deposited using a number of coating techniques including, but not limited to, thermal
spraying, cold spraying, weld overlay, laser beam surface glazing, ion implantation
and vapor deposition. Using a scanned laser or electron beam, a surface can be glazed
and cooled rapidly to form an amorphous surface layer. In glazing, it may be advantageous
to modify the surface composition to ensure good glass forming ability and to increase
hardness and wear resistance. This may be done by alloying into the molten pool on
the surface as the heat source is scanned. Hardfacing coatings may be applied also
by thermal spraying including plasma spraying in air or in vacuum. Thinner, fully
amorphous coatings as coatings for oil and gas well production devices may be obtained
by thin film deposition techniques including, but not limited to, sputtering, chemical
vapor deposition (CVD) and electrodeposition. Some amorphous alloy compositions disclosed
herein, such as near equiatomic stoichiometry (e.g., Ni-Ti), may be amorphized by
heavy plastic deformation such as shot peening or shock loading. The amorphous alloys
as coatings for oil and gas well production devices disclosed herein yield an outstanding
balance of wear and friction performance and require adequate glass forming ability
for the production methodology to be utilized.
Ni-P Based Composite Coatings:
[0209] Electroless and electro plating of nickel-phosphorous (Ni-P) based composites as
coatings for sleeved oil and gas well production devices disclosed herein may be formed
by codeposition of inert particles onto a metal matrix from an electrolytic or electroless
bath. The Ni-P composite coating provides excellent adhesion to most metal and alloy
substrates. The final properties of these coatings depend on the phosphorous content
of the Ni-P matrix, which determines the structure of the coatings, and on the characteristics
of the embedded particles such as type, shape and size. Ni-P coatings with low phosphorus
content are crystalline Ni with supersaturated P. With increasing P content, the crystalline
lattice of nickel becomes more and more strained and the crystallite size decreases.
At a phosphorous content greater than 12 wt%, or 13 wt%, or 14 wt% or 15 wt%, the
coatings exhibit a predominately amorphous structure. Annealing of amorphous Ni-P
coatings may result in the transformation of amorphous structure into an advantageous
crystalline state. This crystallization may increase hardness, but deteriorate corrosion
resistance. The richer the alloy in phosphorus, the slower the process of crystallization.
This expands the amorphous range of the coating. The Ni-P composite coatings can incorporate
other metallic elements including, but not limited to, tungsten (W) and molybdenum
(Mo) to further enhance the properties of the coatings. The nickel-phosphorous (Ni-P)
based composite coating disclosed herein may include micron-sized and sub-micron sized
particles. Non-limiting exemplary particles include: diamonds, nanotubes, carbides,
nitrides, borides, oxides and combinations thereof. Other non-limiting exemplary particles
include plastics (e.g., fluoro-polymers) and hard metals.
Layered Materials and Novel Fullerene Based Composite Coating Layers:
[0210] Layered materials such as graphite, MoS
2 and WS
2 (platelets of the 2H polytype) may be used as coatings for sleeved oil and gas well
production devices. In addition, fullerene based composite coating layers which include
fullerene-like nanoparticles may also be used as coatings for oil and gas well production
devices. Fullerene-like nanoparticles have advantageous tribological properties in
comparison to typical metals while alleviating the shortcomings of conventional layered
materials (e.g., graphite, MoS
2). Nearly spherical fullerenes may also behave as nanoscale ball bearings. The main
favorable benefit of the hollow fullerene-like nanoparticles may be attributed to
the following three effects, (a) rolling friction, (b) the fullerene nanoparticles
function as spacers, which eliminate metal to metal contact between the asperities
of the two mating metal surfaces, and (c) three body material transfer. Sliding/rolling
of the fullerene-like nanoparticles in the interface between rubbing surfaces may
be the main friction mechanism at low loads, when the shape of nanoparticle is preserved.
The beneficial effect of fullerene-like nanoparticles increases with the load. Exfoliation
of external sheets of fullerene-like nanoparticles was found to occur at high contact
loads (∼1GPa). The transfer of delaminated fullerene-like nanoparticles appears to
be the dominant friction mechanism at severe contact conditions. The mechanical and
tribological properties of fullerene-like nanoparticles can be exploited by the incorporation
of these particles in binder phases of coating layers. In addition, composite coatings
incorporating fullerene-like nanoparticles in a metal binder phase (e.g., Ni-P electroless
plating) can provide a film with self-lubricating and excellent anti-sticking characteristics
suitable for coatings for sleeved oil and gas well production devices.
Advanced Boride Based Cermets and Metal Matrix Composites:
[0211] Advanced boride based cermets and metal matrix composites as coatings for sleeved
oil and gas well production devices may be formed on bulk materials due to high temperature
exposure either by heat treatment or incipient heating during wear service. For instance,
boride based cermets (e.g., TiB
2-metal), the surface layer is typically enriched with boron oxide (e.g, B
2O
3) which enhances lubrication performance leading to low friction coefficient.
Quasicrystalline Materials:
[0212] Quasicrystalline materials may be used as coatings for sleeved oil and gas well production
devices. Quasicrystalline materials have periodic atomic structure, but do not conform
to the 3-D symmetry typical of ordinary crystalline materials. Due to their crystallographic
structure, most commonly icosahedral or decagonal, quasicrystalline materials with
tailored chemistry exhibit unique combination of properties including low energy surfaces,
attractive as a coating material for oil and gas well production devices. Quasicrystalline
materials provide non-stick surface properties due to their low surface energy (∼30
mJ/m
2) on stainless steel substrate in icosahedral Al-Cu-Fe chemistries. Quasicrystalline
materials as coating layers for oil and gas well production devices may provide a
combination of low friction coefficient (∼0.05 in scratch test with diamond indentor
in dry air) with relatively high microhardness (400∼600 HV) for wear resistance. Quasicrystalline
materials as coating layers for oil and gas well production devices may also provide
a low corrosion surface and the coated layer has smooth and flat surface with low
surface energy for improved performance. Quasicrystalline materials may be deposited
on a metal substrate by a wide range of coating technologies, including, but not limited
to, thermal spraying, vapor deposition, laser cladding, weld overlaying, and electrodeposition.
Super-hard Materials (Diamond, Diamond Like Carbon, Cubic Boron Nitride):
[0213] Super-hard materials such as diamond, diamond-like-carbon (DLC) and cubic boron nitride
(CBN) may be used as coatings for sleeved oil and gas well production devices. Diamond
is the hardest material known to man and under certain conditions may yield ultra-low
coefficient of friction when deposited by chemical vapor deposition (abbreviated herein
as CVD) on the sleeve element. In one form, the CVD deposited carbon may be deposited
directly on the surface of the sleeve. In another form, an undercoating of a compatibilizer
material (also referred to herein as a buffer layer) may be applied to the sleeve
element prior to diamond deposition. For example, when used on sleeves for drill stem
assemblies, a surface coating of CVD diamond may provide not only reduced tendency
for sticking of cuttings at the surface, but also function as an enabler for using
spiral stabilizers in operations with gumbo prone drilling (such as for example in
the Gulf of Mexico). Coating the flow surface of the spiral stabilizers with CVD diamond
may enable the cuttings to flow past the stabilizer up hole into the drill string
annulus without sticking to the stabilizer.
[0214] In one advantageous embodiment, diamond-like-carbon (DLC) may be used as coatings
for sleeved oil and gas well production devices. DLC refers to amorphous carbon material
that display some of the unique properties similar to that of natural diamond. The
diamond-like-carbon (DLC) suitable for sleeved oil and gas well production devices
may be chosen from ta-C, ta-C:H, DLCH, PLCH, GLCH, Si-DLC, Me-DLC, F-DLC and combinations
thereof. DLC coatings include significant amounts of sp
3 hybridized carbon atoms. These sp
3 bonds may occur not only with crystals - in other words, in solids with long-range
order - but also in amorphous solids where the atoms are in a random arrangement.
In this case there will be bonding only between a few individual atoms, that is short-range
order, and not in a long-range order extending over a large number of atoms. The bond
types have a considerable influence on the material properties of amorphous carbon
films. If the sp
2 type is predominant the DLC film may be softer, whereas if the sp
3 type is predominant, the DLC film may be harder.
[0215] DLC coatings may be fabricated as amorphous, flexible, and yet purely sp
3 bonded "diamond". The hardest is such a mixture, known as tetrahedral amorphous carbon,
or ta-C (see Figure 17). Such ta-C includes a high volume fraction (∼80%) of sp
3 bonded carbon atoms. Optional fillers for the DLC coatings, include, but are not
limited to, hydrogen, graphitic sp
2 carbon, and metals, and may be used in other forms to achieve a desired combination
of properties depending on the particular application. The various forms of DLC coatings
may be applied to a variety of substrates that are compatible with a vacuum environment
and that are also electrically conductive. DLC coating quality is also dependent on
the fractional content of alloying elements such as hydrogen. Some DLC coating methods
require hydrogen or methane as a precursor gas, and hence a considerable percentage
of hydrogen may remain in the finished DLC material. In order to further improve their
tribological and mechanical properties, DLC films are often modified by incorporating
other alloying elements. For instance, the addition of fluorine (F), and silicon (Si)
to the DLC films lowers the surface energy and wettability. The reduction of surface
energy in fluorinated DLC (F-DLC) is attributed to the presence of -CF2 and -CF3 groups
in the film. However, higher F contents may lead to a lower hardness. The addition
of Si may reduce surface energy by decreasing the dispersive component of surface
energy. Si addition may also increase the hardness of the DLC films by promoting sp
3 hybridization in DLC films. Addition of metallic elements (e.g., W, Ta, Cr, Ti, Mo)
to the film, as well as the use of such metallic interlayer can reduce the compressive
residual stresses resulting in better mechanical integrity of the film upon compressive
loading.
[0216] The diamond-like phase or sp
3 bonded carbon of DLC is a thermodynamically metastable phase while graphite with
sp
2 bonding is a thermodynamically stable phase. Thus the formation of DLC coating films
requires non-equilibrium processing to obtain metastable sp
3 bonded carbon. Equilibrium processing methods such as evaporation of graphitic carbon,
where the average energy of the evaporated species is low (close to kT where k is
Boltzmann's constant and T is temperature in absolute temperature scale), lead to
the formation of 100% sp
2 bonded carbons. The methods disclosed herein for producing DLC coatings require that
the carbon in the sp
3 bond length be significantly less than the length of the sp
2 bond. Hence, the application of pressure, impact, catalysis, or some combination
of these at the atomic scale may force sp
2 bonded carbon atoms closer together into sp
3 bonding. This may be done vigorously enough such that the atoms cannot simply spring
back apart into separations characteristic of sp
2 bonds. Typical techniques either combine such a compression with a push of the new
cluster of sp
3 bonded carbon deeper into the coating so that there is no room for expansion back
to separations needed for sp
2 bonding; or the new cluster is buried by the arrival of new carbon destined for the
next cycle of impacts.
[0217] The DLC coatings disclosed herein may be deposited by physical vapor deposition,
chemical vapor deposition, or plasma assisted chemical vapor deposition coating techniques.
The physical vapor deposition coating methods include RF-DC plasma reactive magnetron
sputtering, ion beam assisted deposition, cathodic arc deposition and pulsed laser
deposition (PLD). The chemical vapor deposition coating methods include ion beam assisted
CVD deposition, plasma enhanced deposition using a glow discharge from hydrocarbon
gas, using a radio frequency (r.f.) glow discharge from a hydrocarbon gas, plasma
immersed ion processing and microwave discharge. Plasma enhanced chemical vapor deposition
(PECVD) is one advantageous method for depositing DLC coatings on large areas at high
deposition rates. Plasma based CVD coating process is a non-line-of-sight technique,
i.e. the plasma conformally covers the part to be coated and the entire exposed surface
of the part is coated with uniform thickness. The surface finish of the part may be
retained after the DLC coating application. One advantage of PECVD is that the temperature
of the substrate part does not increase above about 150°C during the coating operation.
The fluorine-containing DLC (F-DLC) and silicon-containing DLC (Si-DLC) films can
be synthesized using plasma deposition technique using a process gas of acetylene
(C
2H
2) mixed with fluorine-containing and silicon-containing precursor gases respectively
(e.g., tetra-fluoro-ethane and hexa-methyl-disiloxane).
[0218] The DLC coatings disclosed herein may exhibit coefficients of friction within the
ranges earlier described. The ultra-low COF may be based on the formation of a thin
graphite film in the actual contact areas. As sp
3 bonding is a thermodynamically unstable phase of carbon at elevated temperatures
of 600 to 1500°C, depending on the environmental conditions, it may transform to graphite
which may function as a solid lubricant. These high temperatures may occur as very
short flash (referred to as the incipient temperature) temperatures in the asperity
collisions or contacts. An alternative theory for the ultra-low COF of DLC coatings
is the presence of hydrocarbon-based slippery film. The tetrahedral structure of a
sp
3 bonded carbon may result in a situation at the surface where there may be one vacant
electron coming out from the surface, that has no carbon atom to attach to (see Figure
18), which is referred to as a "dangling bond" orbital. If one hydrogen atom with
its own electron is put on such carbon atom, it may bond with the dangling bond orbital
to form a two-electron covalent bond. When two such smooth surfaces with an outer
layer of single hydrogen atoms slide over each other, shear will take place between
the hydrogen atoms. There is no chemical bonding between the surfaces, only very weak
van der Waals forces, and the surfaces exhibit the properties of a heavy hydrocarbon
wax. As illustrated in Figure 18, carbon atoms at the surface may make three strong
bonds leaving one electron in the dangling bond orbital pointing out from the surface.
Hydrogen atoms attach to such surface which becomes hydrophobic and exhibits low friction.
[0219] The DLC coatings for sleeved oil and gas well production devices disclosed herein
also prevent wear due to their tribological properties. In particular, the DLC coatings
disclosed herein are resistant to abrasive and adhesive wear making them suitable
for use in applications that experience extreme contact pressure, both in rolling
and sliding contact.
[0220] In addition to low friction and wear/abrasion resistance, the DLC coatings for sleeved
oil and gas well production devices disclosed herein also exhibit durability and adhesive
strength to the outer surface of the body assembly for deposition. DLC coating films
may possess a high level of intrinsic residual stress (∼1GPa) which has an influence
on their tribological performance and adhesion strength to the substrate (e.g., steel)
for deposition. Typically DLC coatings deposited directly on steel surface suffer
from poor adhesion strength. This lack of adhesion strength restricts the thickness
and the incompatibility between DLC and steel interface, which may result in delamination
at low loads. To overcome these problems, the DLC coatings disclosed herein may also
include interlayers of various metallic (for example, but not limited to, Cr, W, Ti)
and ceramic compounds (for example, but not limited to, CrN, SiC) between the outer
surface of the oil and gas well production device and the DLC coating layer. These
ceramic and metallic interlayers relax the compressive residual stress of the DLC
coatings disclosed herein to increase the adhesion and load carrying capabilities.
An alternative approach to improving the wear/friction and mechanical durability of
the DLC coatings disclosed herein is to incorporate multilayers with intermediate
buffering layers to relieve residual stress build-up and/or duplex hybrid coating
treatments. In one form, the outer surface of the oil and gas well production device
for treatment may be nitrided or carburized, a precursor treatment prior to DLC coating
deposition, in order to harden and retard plastic deformation of the substrate layer
which results in enhanced coating durability.
Multi-layered coatings and hybrid coatings:
[0221] Multi-layered coatings on sleeved oil and gas well production devices are disclosed
herein and may be used in order to maximize the thickness of the coatings for enhancing
their durability. The coated sleeved oil and gas well production devices disclosed
herein may include not only a single layer, but also two or more coating layers. For
example, two, three, four, five or more coating layers may be deposited on portions
of the sleeve element. Each coating layer may range from 0.5 to 5000 microns in thickness
with a lower limit of 0.5, 0.7, 1.0, 3.0, 5.0, 7.0, 10.0, 15.0, or 20.0 microns and
an upper limit of 25, 50, 75, 100, 200, 500, 1000, 3000, or 5000 microns. The total
thickness of the multi-layered coating may range from 0.5 to 30,000 microns. The lower
limit of the total multi-layered coating thickness may be 0.5, 0.7, 1.0, 3.0, 5.0,
7.0, 10.0, 15.0, or 20.0 microns in thickness. The upper limit of the total multi-layered
coating thickness may be 25, 50, 75, 100, 200, 500, 1000, 3000, 5000, 10000, 15000,
20000, or 30000 microns in thickness.
[0222] In the embodiments of the coated sleeved oil and gas well production devices according
to the invention as disclosed herein, the body assembly of the oil and gas well production
device includes hardbanding on at least a portion of the exposed outer surface to
provide enhanced wear resistance and durability. Hence, the one or more coating layers
are deposited on top of the hardbanding to form a hybrid type coating structure. The
thickness of hardbanding layer may range from several times that of to equal to the
thickness of the outer coating layer or layers. Non-limiting exemplary hardbanding
materials include cermet based materials, metal matrix composites, nanocrystalline
metallic alloys, amorphous alloys and hard metallic alloys. Other non-limiting exemplary
types of hardbanding include carbides, nitrides, borides, and oxides of elemental
tungsten, titanium, niobium, molybdenum, iron, chromium, and silicon dispersed within
a metallic alloy matrix. Such hardbanding may be deposited by weld overlay, thermal
spraying or laser/electron beam cladding.
[0223] The coatings for use in coated sleeved oil and gas well production devices disclosed
herein may also include one or more buffer layers (also referred to herein as adhesive
layers). The one or more buffer layers may be interposed between the outer surface
of the body assembly and the single layer or the two or more layers in a multi-layer
coating configuration. The one or more buffer layers may be chosen from the following
elements or alloys of the following elements: silicon, titanium, chromium, tungsten,
tantalum, niobium, vanadium, zirconium, and/or hafnium. The one or more buffer layers
may also be chosen from carbides, nitrides, carbo-nitrides, oxides of the following
elements: silicon, titanium, chromium, tungsten, tantalum, niobium, vanadium, zirconium,
and/or hafnium. The one or more buffer layers are generally interposed between the
hardbanding (when utilized) and one or more coating layers or between coating layers.
The buffer layer thickness may be a fraction of or approach the thickness of the coating
layer.
[0224] In the embodiments of the coated sleeved oil and gas well production devices according
to the invention and as disclosed herein, the body assembly further includes one or
more buttering layers interposed between the outer surface of the body assembly and
the coating or hardbanding layer on at least a portion of the exposed outer surface
to provide enhanced toughness, to minimize any dilution from the substrate steel alloying
into the outer coating or hardbanding, and to minimize residual stress absorption.
Non-limiting exemplary buttering layers include stainless steel or a nickel based
alloy. The one or more buttering layers are generally positioned adjacent to or on
top of the body assembly of the oil and gas well production device for coating.
[0225] In one advantageous embodiment of the coated sleeved oil and gas well production
devices disclosed herein, multilayered carbon based amorphous coating layers, such
as diamond-like-carbon (DLC) coatings, may be applied to the device. The diamond-like-carbon
(DLC) coatings suitable for oil and gas well production device may be chosen from
ta-C, ta-C:H, DLCH, PLCH, GLCH, Si-DLC, Me-DLC, N-DLC, O-DLC, B-DLC, F-DLC and combinations
thereof. One particularly advantageous DLC coating for such applications is DLCH or
ta-C:H. The structure of multi-layered DLC coatings may include individual DLC layers
with adhesion or buffer layers between the individual DLC layers. Exemplary adhesion
or buffer layers for use with DLC coatings include, but are not limited to, the following
elements or alloys of the following elements: silicon, titanium, chromium, tungsten,
tantalum, niobium, vanadium, zirconium, and/or hafnium. Other exemplary adhesion or
buffer layers for use with DLC coatings include, but are not limited to, carbides,
nitrides, carbo-nitrides, oxides of the following elements: silicon, titanium, chromium,
tungsten, tantalum, niobium, vanadium, zirconium, and/or hafnium. These buffer or
adhesive layers act as toughening and residual stress relieving layers and permit
the total DLC coating thickness for multi-layered embodiments to be increased while
maintaining coating integrity for durability.
[0226] In yet another advantageous form of the coated sleeved oil and gas well production
devices disclosed herein, to improve the durability, mechanical integrity and downhole
performance of relatively thin DLC coating layers, a hybrid coating approach may be
utilized wherein one or more DLC coating layers may be deposited on a state-of-the-art
hardbanding. This embodiment provides enhanced DLC-hardbanding interface strength
and also provides protection to the downhole devices against premature wear should
the DLC either wear away or delaminate. In another form of this embodiment, an advanced
surface treatment may be applied to the steel substrate prior to the application of
DLC layer(s) to extend the durability and enhance the wear, friction, fatigue and
corrosion performance of DLC coatings. Advanced surface treatments may be chosen from
ion implantation, nitriding, carburizing, shot peening, laser and electron beam glazing,
laser shock peening, and combinations thereof. Such surface treatment can harden the
substrate surface by introducing additional species and/or introduce deep compressive
residual stress resulting in inhibition of the crack growth induced by impact and
wear damage. In yet another form of this embodiment, one or more buttering layers
as previously described may be interposed between the substrate and the hardbanding
with one or more DLC coating layers interposed on top of the hardbanding.
[0227] Figure 26 is an exemplary embodiment of a coating on a sleeved oil and gas well production
device utilizing multi-layer hybrid coating layers, wherein a DLC coating layer is
deposited on top of hardbanding on a steel substrate. In another form of this embodiment,
the hardbanding may be post-treated (e.g., etched) to expose the alloy carbide particles
to enhance the adhesion of DLC coatings to the hardbanding as also shown in Figure
26. Such hybrid coatings can be applied to downhole devices such as the tool joints
and stabilizers to enhance the durability and mechanical integrity of the DLC coatings
deposited on these devices and to provide a "second line of defense" should the outer
layer either wear-out or delaminate, against the aggressive wear and erosive conditions
of the downhole environment in subterraneous rotary drilling operations. In another
form of this embodiment, one or more buffer layers and/or one or more buttering layers
as previously described may be included within the hybrid coating structure to further
enhance properties and performance oil and gas well drilling, completions and production
operations.
[0228] Application of these coating technologies to sleeves proximal to oil and gas well
production devices provide potential benefits, including, but not limited to drilling,
completions, stimulation, workover, and production operations. Efficient and reliable
drilling, completions, stimulation, workover, and production operations may be enhanced
by the application of such coatings to sleeved devices to mitigate friction, wear,
erosion, corrosion, and deposits, as was discussed in detail above.
Exemplary Method of Using Coated Sleeved Device Embodiments:
[0229] In one exemplary embodiment, a coated sleeved oil and gas well production device
comprises providing a coated oil and gas well production device including one or more
cylindrical bodies with one or more sleeves proximal to the outer diameter or the
inner diameter of the one or more cylindrical bodies, and a coating on at least a
portion of the inner sleeve surface, the outer sleeve surface, or a combination thereof
of the one or more sleeves, wherein the coating is chosen from an amorphous alloy,
a heat-treated electroless or electro plated based nickel-phosphorous composite with
a phosphorous content greater than 12 wt%, graphite, MoS
2, WS
2, a fullerene based composite, a boride based cermet, a quasicrystalline material,
a diamond based material, diamond-like-carbon (DLC), boron nitride, and combinations
thereof, and utilizing the coated sleeved oil and gas well production device in well
construction, completion, or production operations.
[0230] In another exemplary embodiment, a coated sleeved oil and gas well production device
comprises providing a coated oil and gas well production device including one or more
bodies with the proviso that the one or more bodies does not include a drill bit,
with one or more sleeves proximal to the outer surface or the inner surface of the
one or more bodies, and a coating on at least a portion of the inner sleeve surface,
the outer sleeve surface, or a combination thereof of the one or more sleeves, wherein
the coating is chosen from an amorphous alloy, a heat-treated electroless or electro
plated based nickel-phosphorous composite with a phosphorous content greater than
12 wt%, graphite, MoS
2, WS
2, a fullerene based composite, a boride based cermet, a quasicrystalline material,
a diamond based material, diamond-like-carbon (DLC), boron nitride, and combinations
thereof, and utilizing the coated sleeved oil and gas well production device in well
construction, completion, or production operations.
TEST METHODS
[0231] Coefficient of friction was measured using ball-on-disk tester according to ASTM
G99 test method. The test method requires two specimens - a flat disk specimen and
a spherically ended ball specimen. A ball specimen, rigidly held by using a holder,
is positioned perpendicular to the flat disk. The flat disk specimen slides against
the ball specimen by revolving the flat disk of 6.8 cm (2.7 inches) diameter in a
circular path. The normal load is applied vertically downward through the ball so
the ball is pressed against the disk. The specific normal load can be applied by means
of attached weights, hydraulic or pneumatic loading mechanisms. During the testing,
the frictional forces are measured using a tension-compression load cell or similar
force-sensitive devices attached to the ball holder. The friction coefficient can
be calculated from the measured frictional forces divided by normal loads. The test
was done at room temperature and 66°C (150°F) under various testing condition sliding
speeds. Quartz or mild steel ball, 4mm ∼ 5 mm diameter, was utilized as a counterface
material.
[0232] Velocity strengthening or weakening was evaluated by measuring the friction coefficient
at various sliding velocities using ball-on-disk friction tester by ASTM G99 test
method described above.
[0233] Hardness was measured according to ASTM C1327 Vickers hardness test method. The Vickers
hardness test method consists of indenting the test material with a diamond indenter,
in the form of a right pyramid with a square base and an angle of 136 degrees between
opposite faces subjected to a load of 9.8 to 980 N (1 to 100 kgf). The full load is
normally applied for 10 to 15 seconds. The two diagonals of the indentation left in
the surface of the material after removal of the load are measured using a microscope
and their average is calculated. The area of the sloping surface of the indentation
is calculated. The Vickers hardness is the quotient obtained by dividing the kgf load
by the square mm area of indentation. The advantages of the Vickers hardness test
are that extremely accurate readings can be taken, and just one type of indenter is
used for all types of metals and surface treatments. The hardness of thin coating
layer (e.g., less than 100µm) has been evaluated by nanoindentation wherein the normal
load (P) is applied to a coating surface by an indenter with well-known pyramidal
geometry (e.g., Berkovich tip, which has a three-sided pyramid geometry). In nanoindentation
small loads and tip sizes are used to eliminate or reduce the effect from the substrate,
so the indentation area may only be a few square micrometers or even nanometers. During
the course of the nanoindentation process, a record of the depth of penetration is
made, and then the area of the indent is determined using the known geometry of the
indentation tip. The hardness can be obtained by dividing the load (kgf) by the area
of indentation (square mm).
[0234] Wear performance was measured by the ball on disk geometry according to ASTM G99
test method. The amount of wear, or wear volume loss of the disk and ball is determined
by measuring the dimensions of both specimens before and after the test. The depth
or shape change of the disk wear track was determined by laser surface profilometry
and atomic force microscopy. The amount of wear, or wear volume loss of the ball was
determined by measuring the dimensions of specimens before and after the test. The
wear volume in ball was calculated from the known geometry and size of the ball.
[0235] Water contact angle was measured according to ASTM D5725 test method. The method
referred to as "sessile drop method" measures a liquid contact angle
goniometer using an optical subsystem to capture the profile of a pure liquid on a solid substrate.
A drop of liquid (e.g., water) was placed (or allowed to fall from a certain distance)
onto a solid surface. When the liquid settled (has become sessile), the drop retained
its surface tension and became ovate against the solid surface. The angle formed between
the liquid/solid interface and the liquid/vapor interface is the contact angle. The
contact angle at which the oval of the drop contacts the surface determines the affinity
between the two substances. That is, a flat drop indicates a high affinity, in which
case the liquid is said to "wet" the substrate. A more rounded drop (by height) on
top of the surface indicates lower affinity because the angle at which the drop is
attached to the solid surface is more acute. In this case the liquid is said to "not
wet" the substrate. The sessile drop systems employ high resolution cameras and software
to capture and analyze the contact angle.
EXAMPLES
Illustrative Example 1:
[0236] DLC coatings were applied on 4142 steel substrates by vapor deposition technique.
DLC coatings had a thickness ranging from 1.5 to 25 micrometers. The hardness was
measured to be in the range of 1,300 to 7,500 Vickers Hardness Number. Laboratory
tests based on ball on disk geometry have been conducted to demonstrate the friction
and wear performance of the coating. Quartz ball and mild steel ball were used as
counterface materials to simulate open hole and cased hole conditions respectively.
In one ambient temperature test, uncoated 4142 steel, DLC coating and commercial state-of-the-art
hardbanding weld overlay coating were tested in "dry" or ambient air condition against
quartz counterface material at 300g normal load and 0.6m/sec sliding speed to simulate
an open borehole condition. Up to 10 times improvement in friction performance (reduction
of friction coefficient) over uncoated 4142 steel and hardbanding could be achieved
in DLC coatings as shown in Figure 19.
[0237] In another ambient temperature test, uncoated 4142 steel, DLC coating and commercial
state-of-the-art hardbanding weld overlay coating were tested against mild steel counterface
material to simulate a cased hole condition. Up to three times improvement in friction
performance (reduction of friction coefficient) over uncoated 4142 steel and hardbanding
could be achieved in DLC coatings as shown in Figure 19. The DLC coating polished
the quartz ball due to higher hardness of DLC coating than that of counterface materials
(i.e., quartz and mild steel). However, the volume loss due to wear was minimal in
both quartz ball and mild steel ball. On the other hand, the plain steel and hardbanding
caused significant wear in both the quartz and mild steel balls, indicating that these
are not very "casing friendly".
[0238] Ball on disk wear and friction coefficient were also tested at ambient temperature
in oil based mud. Quartz ball and mild steel balls were used as counterface materials
to simulate open hole and cased hole respectively. The DLC coating exhibited significant
advantages over commercial hardbanding as shown in Figure 20. Up to 30% improvement
in friction performance (reduction of friction coefficient) over uncoated 4142 steel
and hardbanding could be achieved with DLC coatings. The DLC coating polished the
quartz ball due to its higher hardness than that of quartz. On the other hand, for
the case of uncoated steel disk, both the mild steel and quartz balls as well as the
steel disc showed significant wear. For a comparable test, the wear behavior of hardbanded
disk was intermediate to that of DLC coated disc and the uncoated steel disc.
[0239] Figure 21 depicts the wear and friction performance at elevated temperatures. The
tests were carried out in oil based mud heated to 66°C (150°F), and again the quartz
ball and mild steel ball were used as counterface materials to simulate an open hole
and cased hole condition respectively. DLC coatings exhibited up to 50% improvement
in friction performance (reduction of friction coefficient) over uncoated 4142 steel
and commercial hardbanding. Uncoated steel and hardbanding caused wear damage in the
counterface materials of quartz and mild steel ball, whereas, significantly lower
wear damage has been observed in the counterface materials rubbed against the DLC
coating.
[0240] Figure 22 shows the friction performance of DLC coating at elevated temperature (66°C
(150°F) and 93°C (200°F)). In this test data, the DLC coatings exhibited low friction
coefficient at elevated temperature up to 93°C (200°F). However, the friction
coefficient of uncoated steel and hardbanding increased significantly with temperature.
Illustrative Example 2:
[0241] In the laboratory wear/friction testing, the velocity dependence (velocity weakening
or strengthening) of the friction coefficient for a DLC coating and uncoated 4142
steel was measured by monitoring the shear stress required to slide at a range of
sliding velocity of 0.3m/sec ∼ 1.8m/sec. Quartz ball was used as a counterface material
in the dry sliding wear test. The velocity-weakening performance of the DLC coating
relative to uncoated steel is depicted in Figure 23. Uncoated 4142 steel exhibits
a decrease of friction coefficient with sliding velocity (i.e. significant velocity
weakening), whereas DLC coatings show no velocity weakening and indeed, there seems
to be a slight velocity strengthening of COF (i.e. slightly increasing COF with sliding
velocity), which may be advantageous for mitigating torsional instability, a precursor
to stick-slip vibrations.
Illustrative Example 3:
[0242] Multi-layered DLC coatings were produced in order to maximize the thickness of the
DLC coatings for enhancing their durability for drill stem assemblies used in drilling
operations. In one form, the total thickness of the multi-layered DLC coating varied
from 6 µm to 25 µm. Figure 24 depicts SEM images of both single layer and multilayer
DLC coatings for drill stem assemblies produced via PECVD. An adhesive layer(s) used
with the DLC coatings was a siliceous buffer layer.
Illustrative Example 4:
[0243] The surface energy of DLC coated substrates in comparison to an uncoated 4142 steel
surface was measured via water contact angle. Results are depicted in Figure 25 and
indicate that a DLC coating provides a substantially lower surface energy in comparison
to an uncoated steel surface. The lower surface energy may provide lower adherence
surfaces for mitigating or reducing bit/stabilizer balling and to prevent formation
of deposits of asphaltenes, paraffins, scale, and/or hydrates.
[0244] Applicants have attempted to disclose all embodiments and applications of the disclosed
subject matter that could be reasonably foreseen. However, there may be unforeseeable,
insubstantial modifications that remain as equivalents. While the present disclosure
has been described in conjunction with specific, exemplary embodiments thereof, it
is evident that many alterations, modifications, and variations will be apparent to
those skilled in the art in light of the foregoing description without departing from
the scope of the present disclosure as specified by the claims. Accordingly, the present
disclosure is intended to embrace all such alterations, modifications, and variations
of the above detailed description.
[0245] When numerical lower limits and numerical upper limits are listed herein, ranges
from any lower limit to any upper limit are contemplated.