Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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COATED SLEEVED OIL AND GAS WELL PRODUCTION DEVICES
FIELD
10011 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
10021 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:
10031 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.
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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.
[004] 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.
[005] 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
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be drilled to a considerable depth and considerable distance from the drilling
platform.
[006] 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.
[007] 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
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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.
[0081 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 irmer 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.
[009] 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
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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.
10101 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.
10111 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
left-
hand 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.
10121 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 Al, "System and Method for Reducing Wear in Drill Pipe
Sections."
10131 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
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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.
[014] 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.
[015] 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.
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Marine Riser Systems:
[016] 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.
[017] 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:
[018] 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
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with thread galling and interference issues, particularly with the more costly
OCTG material alloys for extreme service requirements.
[019] 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:
[020] 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.
10211 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.
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10221 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:
[023] 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.
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[024] 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:
[025] 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.
[026] 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
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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.
[027] 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:
[028] 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, CorodTM, 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.
[029] 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,
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and other devices that may fail to operate properly due to friction, wear,
corrosion,
erosion, or deposits.
[030] 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:
[031] 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.
[032] 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:
[033] In addition to the prior art disclosed above, U.S. Patent Application
2008/0236842, "Downhole Oilfield Apparatus Comprising a Diamond-Like
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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.
10341 Saenger and Desroches describe in EP 2090741 Al 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
0-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.
10351 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.
[036] 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
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example U. S. Patent 7,541,069, "Method and System for Coating Internal
Surfaces Using Reverse-Flow Cycling."
[037] 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."
[038] Gammage et al. discloses spray metal application to the external
surface
of downhole tool components in U. S. Patent 7,487,840.
10391 Thornton discloses the use of Tungsten Disulphide (WS,) on downhole
tools in WO 2007/091054, "Improvements In and Relating to Downhole Tools."
[040] 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."
[041] 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."
Need for the Disclosure:
[042] 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
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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.
10431 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-
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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
10441 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 sleevesõ
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, MoS2, WS2, a fifflerene based composite, a
boride
based cermet, a quasicrystalline material, a diamond based material,
diamond-like-carbon (DLC), boron nitride, and combinations thereof.
10451 A further aspect of the present disclosure relates to an advantageous
coated sleeved oil and gas well production device comprising: 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 based nickel¨
phosphorous based composite with a phosphorous content greater than 12 wt%,
graphite, MoS7, WS2, a fullerene based composite, a boride based cermet, a
quasicrystalline material, a diamond based material, diamond-like-carbon
(DLC),
boron nitride, and combinations thereof.
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[046] A still further aspect of the present disclosure relates to an
advantageous method of using a coated sleeved oil and gas well production
device
comprising: 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.), WS.), 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.
[047] A still yet further aspect of the present disclosure relates to an
advantageous method of using a coated sleeved oil and gas well production
device
comprising: 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, MoS2, WS2, 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.
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[048] 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
[049] 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:
[050] 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.
[051] Figure 2 depicts exemplary application of a coating applied to a
sleeved drill stem assembly for subterreaneous drilling applications.
[052] 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.
[053] Figure 4 depicts exemplary application of a coating applied to a
marine
riser system with coated sleeve wear bushings.
[054] Figure 5 depicts exemplary application of coated sleeves applied to
polished rods, sucker rods, and pumps used in downhole pumping operations.
[055] Figure 6 depicts exemplary application of coated sleeves applied to
perforating guns, packers, and logging tools.
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[056] 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.
[057] 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.
[058] 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.
[059] Figure 10 depicts exemplary application of coated sleeves applied to
an
orifice meter, a choke, and a turbine meter.
[060] Figure 11 depicts exemplary application of a coated sleeves applied
to
the grapple and overshot of a washover fishing tool.
[061] Figure 12 depicts exemplary application of a coating applied to a
threaded connection and illustrates thread galling.
[062] 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.
[063] Figure 14 depicts, schematically, the rate of penetration (ROP)
versus
weight on bit (WOB) during subterraneous rotary drilling.
[064] Figure 15 depicts the relationship between coating COF and coating
hardness for some of the coatings disclosed herein versus steel base case.
[065] Figure 16 depicts a representative stress-strain curve showing the
high
elastic limit of amorphous alloys compared to that of crystalline
metals/alloys.
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10661 Figure 17 depicts a ternary phase diagram of amorphous carbons.
[067] Figure 18 depicts a schematic illustration of the hydrogen dangling
bond theory.
[068] Figure 19 depicts the friction and wear performance of DLC coating in
a dry sliding wear test.
[069] Figure 20 depicts the friction and wear performance of the DLC
coating in oil based mud.
[070] Figure 21 depicts the friction and wear performance of DLC coating at
elevated temperature (150 F) sliding wear test in oil based mud.
[071] Figure 22 depicts the friction performance of DLC coating at elevated
temperatures (150 F and 200 F) in comparison to that of uncoated bare steel
and
hardbanding in oil based mud.
[072] Figure 23 depicts the velocity-weakening performance of DLC coating
in comparison to an uncoated bare steel substrate.
[073] Figure 24 depicts SEM cross-sections of single layer and multi-
layered
DLC coatings disclosed herein.
[074] Figure 25 depicts water contact angle for DLC coatings versus
uncoated 4142 steel.
[075] Figure 26 depicts an exemplary schematic of hybrid DLC coating on
hardbanding for drill stem assemblies.
DEFINITIONS
[076] "Annular isolation valve" is a valve at the surface to control flow
from
the annular space between casing and tubing.
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[077] "Asphaltenes" are heavy hydrocarbon chains that may be deposited on
the walls of pipes and other flow equipment and therefore create a flow
restriction.
[078] "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.
[079] "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.
[080] "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.
10811 "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.
[082] "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.
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Typically, multiple casing strings are installed in the wellbore of
progressively
smaller diameter.
[083] "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.
[084] "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.
[085] "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.
[086] "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.
[087] "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.
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[088] "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.
[089] "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.
[090] "Connection pin" is a piece of pipe with the threads on the external
surface of the pipe.
[091] "Connection box" is a piece of pipe with the threads on the internal
surface of the pipe.
[092] "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. W02002/103161A2).
[093] "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.
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[094] "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 downholc 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.
[095] CorodTM is a continuous coiled tubular used as a sucker rod in rod
pumping production operations.
[096] "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.
[097] "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.
[098] "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.
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[099] "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.
[0100] "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.
[0101] "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.
[0102] "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.
[0103] "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.
[0104] "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.
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101051 "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.
[0106] "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.
[0107] "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.
[0108] "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.
[0109] "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.
[0110] "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
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applied to this four-, six-, or perhaps eight-sided piece of pipe to rotate
the drill
pipe that is connected below.
[0111]
"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.
[0112]
"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.
[0113]
"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.
[0114]
"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.
[0115]
"MazefloTm" 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).
[0116]
MoynoTM pumps" and "progressive cavity pumps" are long cylindrical
pumps installed in downhole motors that generate rotary torque in a shaft as
the
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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.
[0117] "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.
[0118] "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.
[0119] "MP35N" is a metal alloy consisting primarily of nickel, cobalt,
chromium, and molybdenum. MP35NTM is considered highly corrosion resistant
and suitable for hostile downhole environments.
[0120] "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.
[0121] "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.
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[0122] "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.
[0123] "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.
[0124] "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.
[0125] "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.
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[0126] "Reciprocating seal assembly" is a seal that is designed to maintain
pressure isolation while two devices are displaced axially.
[0127] "Roller cone bit" is an earth-boring device equipped with conical
shaped cutting elements, usually three, to make a hole in the ground.
[0128] "Rotating seal assembly" is a seal that is designed to maintain
pressure
isolation while two devices are displaced in rotation.
[0129] "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.
[0130] "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.
[0131] "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.
[0132] "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.
[0133] "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.
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4,945,991, 5,113,935, and PCT Patent Publication Nos. W02007/092082,
W02007/092083, W02007/126496, and W02008/060479.
[0134] "Sidepocket" is an offset heavy-wall sub in the tubing for placing
gas
lift valves, temperature and pressure probes, injection line valves, etc.
[0135] "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.
[0136] "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.
[0137] "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.
[0138] "Stimulation treatment" lines are pipe used to connect pumping
equipment to the wellhead for the purpose of conducting a stimulation
treatment.
[0139] "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
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set to automatically close if the rate exceeds a set value, for instance if
containment was lost at the surface.
[0140] "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.
[0141] "Surface flowlines" are pipe used to connect the wellhead to
production
facilities, or alternatively, for discharge of fluid to the pits or flare
stack.
101421 "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.
[0143] "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.
[0144] "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.
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[0145]
"Tubing" is pipe installed in a well inside casing to allow fluid flow to
the surface.
[0146]
"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.
[0147]
"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.
[0148] "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.
[0149]
"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.
[0150]
"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.
=
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[0151] "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.
[0152] (Note: Several of the above definitions are from A Dictionary for
the
Petroleum Industry, Third Edition, The University of Texas at Austin,
Petroleum
Extension Service, 2001.)
DETAILED DESCRIPTION
[0153] 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.
[0154] 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.
[0155] 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
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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").
[0156] 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.
[0157] 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.
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[0158]
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.
101591
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 TA 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 IC and ID are
schematics of producing wells 20 and injection wells 22. Figure lE is a
schematic
of a perforating gun 24. Figure 1F 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.
101601 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/m2. There is art to
choosing the
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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.
[0161] U.S. Patent Application No. 12/583,292 filed on August 18, 2009,
discloses the use of ultra-low friction coatings on drill stem assemblies used
in oil
and gas drilling applications. U.S. Patent Application No. 12/583,302 filed on
August 18, 2009, discloses the use of coatings on oil and gas well production
devices.
[0162] 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.
[0163] There arc 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
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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.
101641 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:
101651 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:
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A. Coated Sleeved Cylindrical Bodies In Sliding Contact Due To Relative
Motion:
[0166] 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.
[0167] 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.
[0168] An exemplary list of such applications is as follows:
101691 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
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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.
[0170] 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.
[0171] 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
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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.
[0172] 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.
[0173] 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
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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.
[0174] Sucker rods and CorodTM 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.
[0175] 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.
=
[0176] Expandable tubulars are typically run in hole, supported with a
hanging
assembly, and then expanded by running a mandrel through the pipe. Coating the
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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.
[0177] 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.
[0178] 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
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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.
101791 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.
101801 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:
101811 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-
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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.
[0182] An exemplary list of such applications is as follows:
[0183] 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.
[0184] 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
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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.
[0185] 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.
[0186] 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, MazefloTM 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
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during stimulation and production at specific locations where the sleeve is
applied.
[0187] 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:
[0188] 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.
[0189] An exemplary list of such applications is as follows:
[0190] 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
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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.
101911 Seats, nipples, valves, sidepockets, mandrels, packer slips, packer
latches, etc. may beneficially use coated sleeve and washer devices with low-
friction coatings.
101921 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.
[0193] 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.
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[0194] 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.
[0195] 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.
[0196] Wear bushings may utilize coated sleeve devices for reduced friction
and wear, and for enhanced operability.
[0197] Coated sleeves in dynamic metal-to-metal seals may be used to
enhance
or replace elastomers in reciprocating and/or rotating seal assemblies.
[0198] MoynoTM 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.
[0199] 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.
[0200] 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.
[0201] 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.
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[0202] 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.
[0203] 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:
[0204] 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.
[0205] 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
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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
102061 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.
[0207] 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
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threading the sleeve and the pin connection so that the sleeve stays with the
pin
during connection makes and breaks.
[0208] 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.
[0209] 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.
[0210] 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
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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.
[0211] 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
[0212] 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.
[0213] 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
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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.
[0214] 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 900, 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.
[0215] 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
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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.
[0216] 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, non-magnetic counterparts of
any
of these devices, and combinations thereof and their associated external
connections.
,
[0217] The coated sleeved oil and gas well production devices
disclosed herein
may be used in drill stem assemblies with downhole temperature ranging from 20
to 400 F with a lower limit of 20, 40, 60, 80, or 100 F, and an upper limit of
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 14 psi to 20,000 psi with a lower limit of 14, 100, 200, 300, 400, 500,
or
1000 psi, and an upper limit of 5000, 10000, 15000, or 20000 psi.
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[0218] 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.
[0219] 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.
[0220] 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
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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.
[0221] 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.
[0222] 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.
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[0223]
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.
[0224]
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.
[0225] 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
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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:
102261 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.
102271 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.
102281 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?,
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WS2, a fullerene based composite, a boride based cermet, a quasicrystalline
material, a diamond based material, diamond-like-carbon (DLC), boron nitride,
and combinations thereof.
[0229] 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, MoS2, WS2, a fullerene based composite,
a
boride based cermet, a quasicrystalline material, a diamond based material,
diamond-like-carbon (DLC), boron nitride, and combinations thereof.
[0230] 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.
[0231] 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
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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.
[0232] 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.,, WS2, a fiillerene 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 (0-DLC), nitrogen
containing diamond-like-carbon (N-DLC), boron containing diamond-like-carbon
(B-DLC), fluorinated diamond-like-carbon (F-DLC) and combinations thereof.
[0233] 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
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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.
102341 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.
102351 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/m2 . In subterraneous rotary drilling
operations, this
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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.
102361 Further details regarding the coatings disclosed herein for use in
coated
sleeved oil and gas well production devices are as follows:
Amorphous Alloys:
102371 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.
102381 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
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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:
102391 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
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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:
102401
Layered materials such as graphite, MoS2 and WS2 (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, MoS2). Nearly spherical fifflerenes 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
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nanoparticles can be exploited by the incorporation of these particles in
binder
phases of coating layers. In
addition, composite coatings incorporating
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:
[0241]
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., TiB2-
metal), the surface layer is typically enriched with boron oxide (e.g, 13203)
which
enhances lubrication performance leading to low friction coefficient.
Quasicrystalline Materials:
[0242]
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/m2)
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
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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):
102431 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.
[0244] 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 sp3 hybridized carbon atoms. These sp3 bonds
may
occur not only with crystals ¨ in other words, in solids with long-range order
¨ but
-
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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 sp2 type is predominant the DLC film may be
softer, whereas if the sp3 type is predominant, the DLC film may be harder.
[0245] DLC coatings may be fabricated as amorphous, flexible, and yet
purely
sp3 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 (AO%) of sp3 bonded carbon atoms. Optional fillers for the DLC
coatings, include, but are not limited to, hydrogen, graphitic sp2 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 sp3 hybridization in DLC films.
Addition of metallic elements (e.g., W, Ta, Cr, Ti, Mo) to the film, as well
as the
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use of such metallic interlayer can reduce the compressive residual stresses
resulting in better mechanical integrity of the film upon compressive loading.
[0246] The diamond-like phase or sp3 bonded carbon of DLC is a
thermodynamically metastable phase while graphite with sp2 bonding is a
thermodynamically stable phase. Thus the formation of DLC coating films
requires non-equilibrium processing to obtain metastable sp3 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% sp2 bonded carbons. The methods disclosed herein for
producing DLC coatings require that the carbon in the sp3 bond length be
significantly less than the length of the sp2 bond. Hence, the application of
pressure, impact, catalysis, or some combination of these at the atomic scale
may
force sp2 bonded carbon atoms closer together into sp3 bonding. This may be
done vigorously enough such that the atoms cannot simply spring back apart
into
separations characteristic of sp2 bonds. Typical techniques either combine
such a
compression with a push of the new cluster of sp3 bonded carbon deeper into
the
coating so that there is no room for expansion back to separations needed for
sp2
bonding; or the new cluster is buried by the arrival of new carbon destined
for the
next cycle of impacts.
[0247] 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
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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 (C2I-12) mixed with fluorine-containing and silicon-containing
precursor
gases respectively (e.g., tetra-fluoro-ethane and hexa-methyl-disiloxane).
102481 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 sp3 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 sp3 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
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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.
102491 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.
[0250] 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
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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:
[0251] 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.
[0252] In another embodiment of the coated sleeved oil and gas well
production devices disclosed herein, the body assembly of the oil and gas well
production device may include 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
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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.
[0253] 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.
[0254] In yet another embodiment of the coated sleeved oil and gas well
production devices disclosed herein, the body assembly may further include 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.
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[0255] 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.
[0256] 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
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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.
[0257] 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.
[0258] 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
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to mitigate friction, wear, erosion, corrosion, and deposits, as was discussed
in
detail above.
Exemplary Method of Using Coated Sleeved Device Embodiments:
102591 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,, WS,, 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.
102601 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,, WS2, a
fullerene
based composite, a boride based cermet, a quasicrystalline material, a diamond
based material, diamond-like-carbon (DLC), boron nitride, and combinations
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thereof, and utilizing the coated sleeved oil and gas well production device
in well
construction, completion, or production operations.
TEST METHODS
[0261] 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 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 150 F under various testing condition sliding speeds. Quartz or mild steel
ball, 4mm ¨ 5 mm diameter, was utilized as a counterface material.
[0262] 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.
[0263] 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
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
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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 100 m)
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).
[0264] 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.
[0265] 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
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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 I:
102661 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.
102671 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
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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".
[0268] 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.
102691 Figure 21 depicts the wear and friction performance at elevated
temperatures. The tests were carried out in oil based mud heated to 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.
102701 Figure 22 shows the friction performance of DLC coating at elevated
temperature (150 F and 200 F). In this test data, the DLC coatings exhibited
low
friction coefficient at elevated temperature up to 200 F. However, the
friction
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coefficient of uncoated steel and hardbanding increased significantly with
temperature.
Illustrative Example 2:
102711 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:
102721 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 pm to 25 vtm. 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:
102731 The surface energy of DLC coated substrates in comparison to an
uncoated 4142 steel surface was measured via water contact angle. Results are
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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.
[0274] 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 spirit or scope of the present
disclosure.
Accordingly, the present disclosure is intended to embrace all such
alterations,
modifications, and variations of the above detailed description.
[0275] When numerical lower limits and numerical upper limits are listed
herein, ranges from any lower limit to any upper limit are contemplated.
