CN102859250B - Through the band sleeve Oil/gas Well process units of coating - Google Patents

Abstract

Band sleeve Oil/gas Well process units through coating comprises Oil/gas Well process units, this Oil/gas Well process units comprises one or more body and one or more sleeve near the outer surface or internal surface of one or more body, and in the coating gone up at least partially of inner sleeve surface, outer sleeve surface or its combination, its floating coat is selected from amorphous alloy, composite material (wherein phosphorus content is greater than 12wt%), graphite, MoS through heat treated nickel-phosphorus based on electroless coating or plating ₂, WS ₂, the composite material based on fullerene, the ceramet based on boride, quasi-crystalline state material, based on adamantine material, diamond-like-carbon (DLC), boron nitride and above-mentioned combination.The described band sleeve Oil/gas Well process units through coating can be provided for that well is built, the friction of the reduction of completion and production of hydrocarbons, wearing and tearing, burn into erosion and deposition.

Description

Coated sleeved oil and gas well production device

technical field

This disclosure relates to the field of oil and gas well production operations. The present disclosure relates more particularly to the use of coated sleeved devices to reduce friction, wear, corrosion, erosion and deposits in oil and gas well production operations. These coated sleeved oil and gas well production devices can be used in drilling rig equipment, subsea riser systems, tubular goods (casing, tubing and drill strings), wellheads, Christmas trees and valves, completion strings and equipment, formation And gravel face completion equipment, artificial lift equipment and workover equipment.

Background technique

Oil and gas well production has fundamental mechanical problems that can be cost-prohibitive or even prohibitive to correct, repair or preserve. Friction is ubiquitous in the oil field, devices in moving contact wear away and lose their original dimensions, and devices degrade due to erosion, corrosion and deposition. These are obstacles to successful operation that can be prevented through the selective use of coated sleeved oil and gas well production devices as described below.

Drilling equipment:

After identifying a particular location as a prospective hydrocarbon zone, production operations begin with the movement and operation of the drilling rig. In rotary drilling operations, a drill bit is attached to the end of a bottom hole assembly that is attached to a drill string including 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 drill the hole in the earth. As the operation progresses, new sections of drill pipe are added to the drill string to increase its overall length. During drilling operations, open boreholes are periodically casing to stabilize the walls and resume drilling operations. As a result, the drill string is typically operated both in an open borehole ("open hole") and within a casing already installed in the borehole ("cased hole"). Alternatively, coiled tubing may replace the drill string in the drilling assembly. The combination of 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 to the drill bit via the drill string and bottom hole assembly. In coiled tubing drilling, power is transmitted to the drill bit through the drilling fluid. The amount of power that can be transmitted by rotation is limited by the maximum torque that the drill string or coiled tubing can withstand.

In an alternative and less common method of drilling, the casing itself is used to drill into the formation. A cutting element is attached to the bottom end of the sleeve, and the sleeve is rotatable to rotate the cutting element. In the following discussion, references to a drill pipe assembly will include a "drilling casing string" used to drill a formation in a "casing while drilling" approach.

During drilling through a subterranean formation, the drill stem assembly makes substantial sliding contact with both the steel casing and the rock formation. This sliding contact is primarily caused by the rotational and axial movement of the drill stem assembly in the borehole. Friction between the moving surfaces of the drill pipe assembly and the stationary surfaces of the casing and formation creates considerable drag on the drill pipe and causes excessive torque and drag during drilling operations. Problems caused by friction are inherent in any drilling operation, but are particularly troublesome in directional drilled or extended reach drilling (ERD) wells. Directional Drilling or ERD is the intentional deviation of a wellbore from vertical. In some cases, the inclination (angle from vertical) can be as large as 90 degrees. Such wells are often referred to as horizontal wells and can be drilled to considerable depths and distances from the drilling platform.

In all drilling operations, the drill pipe assembly tends to sit against the side of the borehole or well casing, but in directional drilled wells this tendency is much greater due to gravity. The drill pipe may also rest locally against the wall of the borehole or the casing in regions of high local curvature of the wall or casing of the borehole. As the length or degree of vertical deviation of the drill string increases, the amount of friction generated by the rotating drill stem assembly also increases. Regions of increased local curvature may increase the amount of friction generated by the rotating drill stem assembly. To overcome this increased friction, additional power is required to rotate the drill stem assembly. In some instances, friction between the drill stem assembly and the casing wall or borehole exceeds the maximum torque the drill stem assembly can withstand and/or the maximum torque capacity of the drilling rig, and drilling operations must be stopped. As a result, the depth of a well that can be drilled with available directional drilling equipment and techniques is ultimately limited by friction.

A string of pipes moving in sliding contact with respect to the outer tube or more generally an inner cylinder moving within the outer cylinder is a common geometry for several of these operations. One prior art method for reducing friction caused by sliding contact between pipe strings is to improve the lubricity of the circulation. In industrial operations, attempts have been made to reduce friction primarily by utilizing water and/or oil based drilling fluid solutions containing various types of expensive and often not environmentally friendly additives. For many of these additives, the increased lubricity obtained from these additives decreases with increasing drilling temperature. Diesel and other mineral oils are commonly used as lubricants, but there are drilling fluid handling issues and these fluids also lose lubricity at elevated temperatures. Certain minerals such as bentonite are known to help reduce friction between the drill stem assembly and the opened borehole. Materials such as Teflon have been used to reduce sliding contact friction; however, these materials lack durability and strength. Other additives include vegetable oils, asphalt, graphite, detergents, glass beads, and walnut shells, but each has its own limitations.

Another prior art method for reducing friction between pipes is to use aluminum for the drill string because aluminum is lighter than steel. However, aluminum is expensive and can be difficult to use in drilling operations, is not as wear resistant as steel, and is incompatible with many fluid types (eg, fluids with high pH). Additionally, the industry has developed means to "float" the inner casing string within the outer string, but during this operation, circulation is limited and it is not suitable for the perforation process.

Yet another method for reducing friction between strings of pipe is to use hard armor material (also referred to herein as hardbanding or hard armor) on the inner pipe string. U.S. Patent No. 4,665,996, which is incorporated herein by reference in its entirety, discloses the use of hard armor applied to the main bearing surface of drill pipe, wherein the alloy has the following composition: 50-65% cobalt, 25-35% Molybdenum, 1-18% chromium, 2-10% silicon and less than 0.1% carbon are used to reduce friction between the pipe string and casing or rock. As a result, the torque required for rotary drilling operations, especially directional drilling, is reduced. The disclosed alloys also provide excellent wear resistance on the drill string while reducing wear on the well casing. Another form of hardbanding is WC-cobalt cermet applied to the drill stem assembly. Other hardbanding materials include TiC, Cr-carbides and other mixed carbide and nitride systems. Alloyed tungsten carbides such as Stellite 6 and Stellite 12 (trademarks of Cabot Corporation) have excellent wear resistance as hard facing materials, but may cause excessive wear of the opposing device. Hardbanding may be applied to portions of the drill stem assembly using welding surfacing or thermal spraying. During drilling operations, the drill stem assembly, which tends to rest against the well casing, continuously wears the well casing as the drill string rotates.

Some sleeved devices have been used in the industry in addition to hardbanding on tool joints. A polymer-steel based wear resistant device is disclosed in US Patent No. 4,171,560 (Garrett, "Method of Assembly a Wear Sleeve a Drill Pipe Assembly."). Western Well Tool then developed and currently offers the Non-Rotating Protector to control the contact between tubing and casing in deviated wellbores, the subject of US Patent Nos. 5,803,193, 6,250,405 and 6,378,633.

Strand et al. have patented a metal "wear sleeve" device (US Patent No. 7,028,788), which is a device for disposing hardbanding material on a removable sleeve. The device is a ring, typically less than one-half inch wall thickness, which is threaded onto a pin connection of a drill pipe tool joint over a portion of a pin having a reduced diameter, up to the bevel diameter of the connection. The ring has internal threads on a portion of the inner surface opposite the left-handed orientation of the tool adapter. Threaded in this way, the ring is not constrained against the pin connection body, but instead it is deflected to the box-pin connection face as the drill string is turned to the right. Arnco marketed the device under the trade name "WearSleeve". After years of being on the market and at least one field trial, the system has not been widely used. The methods disclosed herein offer clear advantages over WearSleeve devices.

Arnco has devised a fixed hardbanding system, usually in the middle of a drill pipe joint, as described in US Patent Publication No. 2007/0209839 Al, "System and Method for Reducing Wear in Drill Pipe Sections".

Separately, tool joint configurations in which pin connections are held in slips have been deployed in the field, as opposed to standard oil industry configurations in which socket connections are held by slips. Certain benefits have been claimed, as in exemplary publications SPE18667 (1989) Dudman, R.A. et al. "Pin-up Drillstring Technology: Design, Application, and Case Histories" and SPE52848 (1999) Dudman, R.A. et al. 000ftSlim-HoleinSouthernOklahoma."Recorded in. Dudman discloses larger pipe diameters and connector sizes for certain hole sizes than are used in standard pin-down practice, because the pin connector diameter can be made smaller than the sleeve connector diameter and still satisfy fishing Require.

There are also many additional equipment components on the rig that have metal-to-metal contact 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, beams, pads, sleeves and pallets used to move drilling rigs and drilling materials and equipment; top drives and lifts equipment; mixers, paddles, compressors, vanes, and turbines; and bearings for rotating equipment and bearings for roller cone bits.

Specific operations other than hole-forming operations are often performed during the drilling process, including: surveying the open hole (or cased hole section) to assess formation properties, drilling core to remove portions of the formation for scientific assessment, capturing bottomhole conditions Subsurface formation fluid for fluid analysis, placing tools against the well to record acoustic signals, and other operations and methods known to those skilled in the art. Most of these operations involve axial or torsional movement of one body relative to the other, where the two bodies come into mechanical contact with a certain contact force and contact friction resisting the relative movement, causing friction and wear.

Subsea riser system:

In a marine environment, an additional complication is that the wellhead tree may be "dry" (on the platform above sea level) or "wet" (on the seabed). In either case, a conduit pipe known as a "riser" is placed between the surface and the seafloor, with drill pipe equipment extending into the riser and drilling fluid returning in the annulus. Risers may be particularly prone to problems associated with rotation of the inner pipe in the outer stationary pipe, since the riser is not fixed but may also move due to contact not only with the drill string but also with the marine environment. Drag and vortex shedding of the subsea riser causes loads and vibrations due in part to the frictional resistance of ocean currents around the outer surface of the subsea riser.

Operations within subsea riser systems typically involve axial or torsional movement of one body relative to the other, where the two bodies come into mechanical contact with a certain contact force and contact friction that overcome the relative movement, causing friction and wear.

Tubular items:

Oil Specific Tubular Goods (OCTG) include drill pipe equipment, casing, tubing, work strings, coiled tubing and risers. Common to most OCTG (but not flexible tubing) is the threaded connection, which suffers from potential failure from improper thread and/or seal interference, causing galling in the mating connector, which can be damaged due to connection and inhibit the use and reuse of the entire pipe joint. Threads can be shot peened, cold rolled, and/or chemically treated (eg, phosphated, copper plated, etc.) to improve their galling properties, and the use of appropriate pipe thread compounds provides benefits for connection use. However, there are still problems today related to thread galling and interference issues, especially with the more expensive OCTG material alloys used for extreme condition inspection requirements.

Operations using OCTG typically involve axial or torsional motion of one body relative to the other, where the two bodies come into mechanical contact with a certain contact force and contact friction that overcome the relative motion, causing friction and wear. Such motion may be required for installation, after which the device may be substantially stationary, or such motion may be required for repeated applications in order to perform certain operations.

Wellheads, Christmas trees and valves:

At the top of the casing, the fluid is contained by wellhead equipment, which typically includes multiple valves and blowout preventers (BOPs) of various types. Subsurface safety valves are critical equipment components that must function correctly during emergency or out-of-control conditions. Subsurface safety valves are installed downhole, usually in the tubing string, and can be sealed to prevent flow from the subsurface. Chokes and flowlines (especially fittings and elbows) connected to wellheads are subject to friction, wear, corrosion, erosion and deposits. The choke may be cut by backflow of sand, for example, making the measurement of flow rate inaccurate.

Many of these devices rely on seals and very tight mechanical tolerances, including both metal-to-metal and elastomeric seals. Many devices (sleeves, bags, nipples, needles, gates, balls, plugs, cross-joints, couplings, packers, stuffing boxes, valve stems, centrifuges, etc.) suffer from frictional and mechanical damage due to corrosion and erosion. degradation, and even potential clogging by deposits of scale, bitumen, paraffin and hydrates. Some of these devices may be installed downhole or subsea, and obtaining service access for repair or restoration may not be possible or may be very expensive.

Operations involving wellheads, trees, and valves typically involve axial or torsional motion of one body relative to another, where the two bodies come into mechanical contact with a certain contact force and contact friction that overcome 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 certain operations. Some of these systems also build static or dynamic seals that require close tolerances and smooth surfaces to prevent leakage.

Completion string and equipment:

Where the well is cased to prevent borehole collapse and uncontrolled fluid flow, completion operations must be performed to prepare the well for production. The operation involves moving equipment in and out of the wellbore to perform operations such as cementing, perforating, producing oil and logging. Two common conveyances for completion equipment are wireline and tubing (drill pipe, coiled tubing, or tubing work string). These operations may include running logging tools to record formation and fluid properties, using perforating guns to create holes in casing to allow hydrocarbon production or fluid injection, employing temporary or permanent plugs to isolate fluid pressure, operating packers to facilitate placement Pipelines to provide a seal between the interior of the pipe and the annulus as well as other types of equipment required to run cement grouting, oil recovery and well completions. Wireline tools and work strings may include packers, straddle packers, and casing patches, in addition to packer placement tools, devices for installing valves and instrumentation in side bags, and for performing well Other types of equipment that operate at the bottom. The placement of these tools, particularly in extended reach wells, can be hampered by frictional drag. The final completion string left in the hole for production is generally referred to as the production tubing string.

The installation and use of completion strings and equipment usually involves axial or torsional movement of one body relative to the other, where the two bodies come into mechanical contact with a certain contact force and contact friction to overcome the relative movement, 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 certain operations.

Formation and gravel face completions:

In many wells, there is a tendency for sand or formation material to flow into the wellbore. To prevent this from happening, a "sand screen" is placed in the well across the completion interval. This operation may include the construction of a dedicated large diameter assembly comprising one of several gravel screen mesh designs on a central "base pipe". Screens and base pipes are frequently subject to erosion and corrosion and can fail due to sand "cutting". Additionally, in high-inclination wells, the frictional drag encountered while feeding the screen into the wellbore may be excessive and limit the use of these devices, or the length of the wellbore may be limited by the frictional resistance that can be screened. Limits the maximum depth of the net run operation.

In those wells where sand control is required, sand-like support material, or "proppant," is pumped into the annulus between the screen and the formation to prevent formation particles from flowing through the screen. This operation is called "gravel pack" or, if performed in a fractured state, may be called "frac pack". In many other formations, often in wellbores without sand screens, a fracture recovery treatment can be performed in which this same or a different type of support material is injected in a fractured state to create a Large supported frac wings at one end distance to increase production or injection rates. Frictional resistance occurs concurrently with the pumping process as the proppant particles contact each other and the confinement walls. In addition, proppant particles are crushed during production and produce "fines" that increase resistance to fluid flow. Proppant properties, including particle strength, coefficient of friction, shape and roughness, are important to the successful performance of the treatment and the eventual increase in the productivity or injection rate of the well.

The installation of sand and gravel screens and the subsequent workover operations usually involve axial or torsional movement of one body relative to the other, where the two bodies come into mechanical contact with a certain contact force and contact friction to overcome 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 certain operations.

Artificial lift equipment:

When starting production from a well, it may flow at a satisfactory rate under its own pressure. However, many wells require assistance in lifting fluids out of the wellbore at some point during their production life. A number of methods are used to lift fluids from wells, including: suction rods, Corod ^™ and electric submersible pumps for removing fluids from wells, plunger lifts for draining fluids from major gas wells, and The density of the small liquid column is "gas lift" or gas injection along the tubing. Optionally, specialty chemicals can be injected through valves spaced along the tubing to prevent build-up of scale, bitumen, paraffin or hydrate deposits.

The production tubing string may include devices for assisting fluid flow. Several of these devices may rely on seals and very tight mechanical tolerances, including both metal-to-metal and elastomeric seals. Interfaces between components (sleeves, bags, plugs, packers, cross-joints, couplings, bores, mandrels, etc.) suffer from frictional and mechanical degradation due to corrosion and erosion, and even from scaling, asphalt Potential clogging or mechanical fit interference caused by deposits of paraffin, hydrate or hydrate. In particular, gas lift devices, submersible pumps, and other artificial lift equipment may include valves, seals, rotors, stators, and other devices that may not function properly due to friction, wear, corrosion, erosion, or deposits.

The installation and operation of artificial lift equipment and subsequent workover operations typically involve axial or torsional movement of one body relative to the other, where the two bodies are in mechanical contact with a certain contact force and contact friction that overcome the relative movement, thereby cause friction and wear.

Workover equipment:

Downhole operations of the wellbore near intervals of the reservoir formation are often required to collect data or to initiate, restore or increase production or injection rates. These operations include running equipment into and out of the wellbore. Two common conveyance means for completion equipment and tools are wireline and pipe. These operations may include running logging tools to record formation and fluid properties, using perforating guns to create holes in casing to allow hydrocarbon production or fluid injection, employing temporary or permanent plugs to isolate fluid pressure, operating packers to facilitate Sealing between intervals in well completions, as well as operating other types of highly specialized equipment. The operation of sending the equipment into and out of the well involves sliding contact caused by the relative motion of the two bodies, creating a frictional drag.

Workover operations typically involve axial or torsional movement of one body relative to another, where the two bodies come into mechanical contact with a certain contact force and contact friction that overcome the relative movement, causing friction and wear.

Related technologies:

In addition to the prior art disclosed above, US Patent Publication No. 2008/0236842, "Downhole Oilfield Apparatus Comprising a Diamond-Like Carbon Coating and Methods of Use," discloses the application of a DLC coating to a downhole device having an interior surface exposed to the downhole environment. This document does not disclose the use of external coatings on sleeved devices, and in particular, this document does not discuss external application to well tool joint components.

Saenger and Desroches in EP2090741A1 describe "a coating on at least a part of the surface of a support" for downhole tool operations. Coatings of this type disclosed include DLC, diamond carbon, and Cavidur (a proprietary DLC coating from Bekaert). The coating is specifically referred to as "inert material selected to reduce friction". Specific applications to well logging tools and O-rings are described. Specific benefits cited include reductions in friction and corrosion. Although a drill string is shown in the figures of this application, there is no mention in this application of coating the drill string or tool joints.

VanDenBrekel et al. in WO2008/138957A2 disclose a method of drilling 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 polytetrafluoroethylene (PTFE) applied as a friction reducing outer layer. This disclosure differs from the present invention because the coating to be applied has a greater hardness value than the casing material and no description of the drilling fluid is provided in the present invention.

Wei et al. also disclose the use of coatings on the interior surfaces of tubular structures (US Patent No. 6,764,714, "Method for Depositing Coating on the Interior Surfaces of Tubular Walls" and US Patent No. 7,052,736, "Method for Depositing Coating on the Interior Surfaces of Tubular Structures"). Tudhope et al. have also developed apparatus for coating the interior surfaces of objects, including, for example, US Patent No. 7,541,069, "Method and System for Coating Internal Surfaces Using Reverse-Flow Cycling."

Griffo in US Patent Publication No. 2008/0127475, "Composite Coating with Nanoparticles for Improved Wear and Lubricity in Downhole Tools," discloses the use of superabrasive nanoparticles on drill bits and components of bottom hole assemblies.

Gammage et al. in US Patent No. 7,487,840 disclose the application of sprayed metal to the exterior surface of a bottom hole tool component.

Thornton in WO2007/091054, "Improvements In and Relating to Downhole Tools" discloses the use of tungsten disulfide (WS ₂ ) on downhole tools.

The use of coatings on drill bits and drill bit seals has been disclosed, for example, in US Pat.

In addition, the use of DLC coatings in non-oilfield applications has been disclosed in US Patent No. 6,156,616 "Synthetic Diamond Coatings with Intermediate Bonding Layers and Methods of Applying Such Coatings" and US Patent No. 5,707,717 "Articles Having Diamond-Like Protective Film".

Necessity for this disclosure:

Given the wide-ranging nature of these broad requirements for production operations, the application of new coating material technologies is required which protects devices from sliding contact between two or more devices and which may contain solid particles moving at high speeds The effects of friction, wear, corrosion, erosion and deposition caused by fluid flow. This need calls for new materials that combine high stiffness with the ability to have a low coefficient of friction (COF) when in contact with opposing surfaces. Furthermore, the use of cased devices is a practical and economical way to deploy such coatings in oil and gas well production equipment. If this coating material can also provide a low-energy surface and a low coefficient of friction against the borehole wall, the new material coating could enable very long-reach drilling, reliable and Efficient operation and can achieve cost reduction, safety and operational improvement in oil and gas well production operations. As envisioned, the use of these coatings on casing well production devices may have wide application and provide significant improvements and extensions to well production operations.

Accordingly, a need exists for a coated sleeved oil and gas well production device. Firstly, the method of applying the coating of the invention on a production device may require the body to be enclosed in a chamber. This can be a very limiting requirement for many oilfield components. For example, the geometry of long pipe sections is inconvenient for such chambers. This may not be very efficient either, since the surface area to be coated may be a very small fraction of the total surface area of the body. The coated sleeved elements of the coated sleeved device can be transported to a field location and installed on production equipment at a lower cost than deploying such low-friction coated alternatives. Also, in certain applications where the sleeve elements or coatings need to be replaced or renewed, the sleeved system is economical to construct with minimal transportation requirements and equipment downtime. The sleeve element itself may comprise a different material than the body it is adjacent to. The sleeve element can be subjected to high temperatures and other environmental conditions during the coating process that can damage other elements of the system. Coated sleeved device sleeve elements can be more effectively coated with low friction materials and with a wider range of possible coating types than attempts to coat larger parts of equipment facilitate the use of low friction materials. Tribological coatings are used to improve the effective mechanical properties of these devices. The prior art does not disclose an effective way of solving these problems, and the method of the present invention will enable the use of low friction coatings in oil and gas well production devices.

Contents of the invention

According to the present disclosure, an advantageous coated sleeved oil and gas well production device comprises: one or more cylindrical bodies, one or more Sleeves and coatings on at least a portion of the inner sleeve surface, the outer sleeve surface, or combinations thereof of one or more sleeves, wherein the coating is selected from amorphous alloys, heat-treated electroless-based or electroplated Nickel-phosphorus composites (where phosphorus content is greater than 12wt%), graphite, MoS ₂ , WS ₂ , fullerene-based composites, boride-based cermets, quasi-crystalline materials, diamond-based materials, Diamond carbon (DLC), boron nitride and combinations of the above.

Another aspect of the present invention relates to advantageous coated sleeved oil and gas well production devices, including oil and gas well production devices comprising: one or more bodies, wherein the one or more bodies do not include a drill bit; one or more sleeves near the outer or inner surface of the one or more bodies; and the 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 layer, wherein the coating is selected from amorphous alloys, heat-treated electroless or electroplated nickel-phosphorous composites (wherein the phosphorus content is greater than 12 wt%), graphite, MoS ₂ , WS ₂ Composite materials, boride-based cermets, quasi-crystalline materials, diamond-based materials, diamond-like carbon (DLC), boron nitride, and combinations of the above.

Yet another aspect of the present invention relates to an advantageous method of using a sleeved oil and gas well production device comprising: providing a coated oil and gas well production device comprising one or more The cylindrical body, one or more sleeves adjacent the outer or inner diameter of the one or more cylindrical bodies, and the inner sleeve surface of the one or more sleeves, the outer sleeve surface, or a combination thereof Coating on at least one part, wherein the coating is selected from the group consisting of amorphous alloys, heat-treated electroless or electroplated nickel-phosphorous composites (wherein the phosphorus content is greater _{than 12} wt%), graphite, MoS Composites of fullerenes, boride-based cermets, quasi-crystalline materials, diamond-based materials, diamond-like carbon (DLC), boron nitride, and combinations thereof; and in well construction, well completion, or production operations Utilize coated, sleeved oil and gas well production devices.

Yet another aspect of the present invention relates to an advantageous method of using a sleeved oil and gas well production device, comprising: providing a coated oil and gas well production device, the coated oil and gas well production device comprising: one or more one or more bodies, wherein the one or more bodies do not include a drill bit; one or more sleeves near the outer or inner surface of the one or more bodies; and the inner sleeve of the one or more sleeves A coating on at least a portion of the surface of the sleeve, the surface of the outer sleeve, or a combination thereof, wherein the coating is selected from the group consisting of amorphous alloys, heat-treated electroless or electroplated nickel-phosphorous composites (wherein the phosphorus content is greater than 12 wt. %), graphite, MoS ₂ , WS ₂ , fullerene-based composites, boride-based cermets, quasi-crystalline materials, diamond-based materials, diamond-like carbon (DLC), boron nitride, and combinations of the above and utilizing the coated sleeved oil and gas well production device in well construction, well completion or production operations.

These and other features and attributes of the disclosed coated sleeved oil and gas well production devices and methods of using such sleeved devices to reduce friction, wear, corrosion, erosion and deposits in these application areas and their Advantageous applications and/or uses of the invention will become apparent from the following detailed description, especially when read in conjunction with the drawings appended hereto.

Description of drawings

To assist those of ordinary skill in the relevant arts in making and using the subject matter of the present invention, reference is made to the accompanying drawings, in which:

Figure 1 depicts an oil and gas well production system employing well production devices throughout the individual well construction, well completion, oil production, well workover and production phases of the overall production process.

Figure 2 depicts an exemplary application of a coating applied to a sleeved drill stem assembly for subterranean drilling applications.

Figure 3 depicts an exemplary application of a coating to a bottomhole assembly device that may be adapted to use a coated sleeve, in this case a reamer, stabilizer, Milling cutters and reamers.

FIG. 4 depicts an exemplary application of a coating applied to a subsea riser system with a coated sleeve abradable bushing.

Figure 5 depicts an exemplary application of coated sleeves applied to polished rods, suction rods and pumps for downhole pumping operations.

Figure 6 depicts an exemplary application of a coated sleeve applied to a perforating gun, packer, and logging tool.

Figure 7 depicts an exemplary application of coatings applied to wire ropes and wire ropes and strands of cable bundles. Coated sleeves can be used in bushings to facilitate smooth rope operation.

Figure 8 depicts exemplary applications of coatings applied to base pipe and screen assemblies used in gravel pack sand control operations and screens used in solids control equipment, while showing that they can be used to assist in sliding the screens into Coated casing in a wellbore.

Figure 9 depicts an exemplary application of a coated sleeve applied to a wellhead and valve assembly, where a sleeved device may be used in a valve to provide sealing at lower operating forces and loads.

FIG. 10 depicts exemplary applications of coated sleeves applied to orifice meters, chokes, and turbine meters.

11 depicts an exemplary application of a coated sleeve applied to a grapple and slip overshot of an overwash fishing tool.

Figure 12 depicts an exemplary application of a coating applied to a threaded connection and shows thread galling.

Figure 13 illustrates an exemplary application of a coated sleeve element in a coated sleeved drill string connection showing pin-down and pin-up connection configurations and additional possible sleeve parameters.

Figure 14 schematically depicts rate of penetration (ROP) versus weight on bit (WOB) during subsurface rotary drilling.

Figure 15 depicts the relationship between coating COF and coating hardness for some coatings disclosed herein compared to steel-based casing.

Figure 16 depicts typical stress-strain curves showing the high elastic limit of amorphous alloys compared to crystalline metals/alloys.

Figure 17 depicts the ternary phase diagram of amorphous carbon.

Figure 18 depicts a schematic representation of the hydrogen dangling bond theory.

Figure 19 depicts the friction and wear properties of DLC coatings in dry sliding wear tests.

Figure 20 depicts the friction and wear performance of DLC coatings in oil-based drilling fluids.

Figure 21 depicts the friction and wear performance of DLC coatings in high temperature (150°F) sliding wear tests in oil-based drilling fluids.

Figure 22 depicts the tribological performance of DLC coatings in oil-based drilling fluids at elevated temperatures (150°F and 200°F) compared to that of uncoated bare steel and hardcoating.

Figure 23 depicts the velocity impairment performance of DLC coatings compared to an uncoated bare steel substrate.

Figure 24 depicts SEM cross-sections of single and multilayer DLC coatings disclosed herein.

Figure 25 depicts the water contact angles of DLC coatings compared to uncoated 4142 steel.

26 depicts an exemplary schematic of a hybrid DLC coating on hardbanding of a drill stem assembly.

definition

An "annular isolation valve" is a valve at the surface to control flow from the annular space between the casing and the tubing.

"Bitumen" are heavy hydrocarbon chains that can deposit on the walls of pipes and other flow equipment and thus form flow constraints.

The "base pipe" is the liner that serves as the carrier for the sand control screen. A screen is attached to the outside of the base pipe. At least a portion of the base pipe may be pre-perforated, grooved or equipped with an inflow control device. The base pipe is made in joint sections that are threaded for extension within the bore while being assembled.

"Bearings and bushings" are used to provide low friction surfaces for two devices to move relative to each other in sliding contact, especially to allow relative rotational motion.

"Abrasion joints" are thicker walled pipes used across flow perforations or in inlets across fluid inlets during oil recovery processes. Greater wall thickness and/or material hardness resists complete erosion due to sand or proppant impact.

A "Bottom Hole Assembly" (BHA) consists of one or more devices including, but not limited to: stabilizers, variable diameter stabilizers, back expansion reamers, drill collars, flexible drill collars, rotary steerable tools, rollers Reamers, damping joints, drilling fluid motors, logging while drilling (LWD) tools, measuring while drilling (MWD) tools, coring tools, reamers, reamers, centralizers, turbines, curved shells bodies, bending motors, drilling jars, acceleration jars, adapters, buffer jars, torque reduction tools, floating subs, fishing tools, fishing jars, casing wash pipes, logging tools, survey tool joints, Non-magnetic fittings of any of these devices, and combinations thereof, and associated external connection devices as described above.

A "casing" is a pipe installed in a wellbore to prevent collapse and to allow drilling to continue below the bottom of the casing string at higher fluid densities without the fluids flowing into the cased formation. Typically, multiple casing strings are installed in progressively smaller diameter wellbores.

A "casing centralizer" is tied to the outside of the casing as it travels through the bore. Centralizers are usually equipped with steel springs or metal fingers that push against the formation to achieve deviation from the formation wall, the purpose of which is to stabilize the casing to provide a more uniform flow around the casing. annulus for a better cement seal. Centralizers may include fingers to scrape the borehole to dislodge drilling fluid debris that may inhibit direct contact of the cement with the formation.

"Casing while drilling" refers to the relatively new and less common method of drilling a well using casing instead of a removable drill string. When the hole segment has reached depth, the casing is left in place, operations are performed to remove or displace the cutting elements at the bottom of the casing, and the cement work can then be pumped.

A "chemical injection system" is used to inject chemical inhibitors into the wellbore to prevent scale, methane hydrate, or other deposits from accumulating in the wellbore, which would limit production.

A "choke" is a device used to restrict the flow rate. Wells are typically tested on a specific choke size, which could be as simple as a plate with holes of specified diameter. As sand or proppant flows through the choke, the pores may erode and the choke size may change, making flow rate measurements inaccurate.

"Coaxial" means that two or more objects have axes that are substantially the same or along the same line. "Out-of-axis" means that objects have axes that may be offset but are substantially parallel or may otherwise not be collinear.

A "completion slip sleeve" is a device installed in the completion string that selectively enables orifices to be opened or closed depending on the state of the sleeve, thereby allowing the production interval to communicate with the tubing or not. In long-term use, successful operation of the sliding sleeve depends on resistance to the operating sleeve due to friction, wear, deposits, erosion and corrosion.

"Complex geometric shape" refers to an object that does not substantially include a single primitive geometric shape such as a sphere, cylinder, or cube. Complex geometries may include multiple simple geometries, such as cylinders, cubes, or spheres with many different radii, or may include simple primitive geometries and other complex geometries.

A "coupling pin" is a pipe fitting with threads on the outer surface of the pipe.

A "sleeve" is a pipe fitting with threads on the inside surface of the pipe.

A "contact ring" is a device attached to a component of a logging tool to enable the tool to face away from the wall of the casing or formation. For example, a contact ring may be mounted at the joint of the perforating gun to enable the gun to face away from the casing wall, for example in applications such as "Just-In-Time Perforating" (PCT Application No. WO2002/103161A2).

"Bordering" means that objects are adjacent to each other such that they share a common edge or face. "Disjointing" means that objects do not have a common edge or face due to being offset or displaced from each other. For example, the tool joints are larger diameter cylinders that are not bordered because the smaller diameter cylinder, ie, the drill pipe, is positioned between the tool joints.

"Control lines" and "conduits" are small diameter tubing that can extend outside a tubing string to provide hydraulic pressure, voltage or electrical current or fiber optic paths to one or more downhole devices. Control lines are used to operate subsurface safety valves, chokes and valves. Injection lines are similar to control lines and can be used to inject specialty chemicals into downhole valves to inhibit scale, bitumen, paraffin or hydrate formation, or to reduce friction.

"Corod ^™ " is a continuous flexible tubing used as a suction rod in rod pumping production operations.

A "coupling" is a connecting device between two pieces of pipe, usually, but not exclusively, a single piece that is threadably adapted to fit two longer pieces joined together by the coupling. For example, a coupler is used to join two suction rods in an artificial lift rod pumping device.

A "cylinder" is (1) a surface bounded by two parallel planes and produced by a straight line moving parallel to a given plane and tracing a curve bounded by the planes and lying in a plane perpendicular or inclined to the given planes or solid, and/or (2) any column or component, whether solid or hollow (source: www.dictionary.com).

A "downhole tool" is a device that is typically retrievably extended into a well, or possibly fixed therein, to perform some function in the wellbore. Some downhole tools run on devices such as measurement while drilling (MWD) while others run on wireline, such as formation logging tools or perforating guns. Some tools run on wire rope or pipe. A packer is a downhole tool that can be run on tubing or wireline to be placed in a wellbore to block flow, and it can be removable or fixed. There are many bottomhole tool arrangements commonly used in the industry.

A "drill collar" is a heavy-walled pipe in a bottomhole tool assembly near the drill bit. The stiffness of the drill collar helps the bit drill in a straight line, while the weight of the collar is used to apply weight to the bit to drill forward.

"Drill pipe" is defined as the entire length of tubular pipe, including drive pipe (if present), drill pipe and drill collars, which make up the drilling assembly from the surface of the hole to the bottom. Drill pipe does not include drill bits. In the specific case of casing while drilling, the string of casing used to drill into the clay formation will be considered part of the drillpipe.

"Drill stem assembly" is defined as the combination of drill string and bottom hole assembly or coiled tubing and bottom hole assembly. Drill stem assemblies do not include drill bits.

"Drill string" is defined as the column or string of drill pipe to which the tool joint is attached, the transition conduit between the drill string and the bottom hole assembly including the tool joint, including the weight of the tool joint and wear pads Quality drill pipe that transmits fluid and rotational power from a top drive or drive pipe to the drill collar and bit. In some references, but not in this document, the term "drill string" includes both drill pipe and drill collars in bottom hole assemblies.

"Elastomeric seals" are used to provide a barrier between two devices, usually metal, to prevent flow from one side of the seal to the other. Elastomeric seals are selected from one of the class of materials that are elastic or resilient.

"Elbows, tees, and couplings" are common plumbing devices used to connect flowlines to complete the flow path of fluids, such as connecting a wellbore to a surface production facility.

"Expandable tubulars" are tubular items such as casing strings and liners that run slightly below gauge in a bore. Once in place, a larger diameter tool or expansion mandrel is forced along the expandable tubular to deform it to the larger diameter.

"Gas lift" is a method of increasing the flow of hydrocarbons in a wellbore by injecting gas into a tubing string through a gas lift valve. This process is typically applied to oil wells, but can also be applied to gas wells where large amounts of water are produced. The increased gas reduces the static head of the fluid column.

"Fiberglass" is typically run downhole and back to the surface in small control lines for measuring downhole properties such as temperature and pressure. Fiberglass can be used to provide continuous readings with fine spatial sampling along the borehole. The fiber is typically pumped down one control line, through a "turn joint" and up into a second control line. Friction and resistance through the steering joint can limit some fiber optic devices.

An "Inflow Control Device" (ICD) is an adjustable orifice, nozzle, or flow channel in the completion string across formation intervals that is used to achieve the flow rate of production fluids into the wellbore. This can be used in conjunction with additional measurements and automation in "smart" completion systems.

A "jar" is a downhole tool used to apply a large axial load or shock when triggered by the operator. Some jars are activated by lowering the weight, while others are activated when pulled upward. Activation of the jar is typically performed to dislodge plugged tubing in the wellbore.

A "drive pipe" is a flat sided polygonal piece of pipe that passes through the rig floor on rigs equipped with older rotary table equipment. Torque is applied to the four, six or eight sided pipe piece to rotate the drill pipe connected underneath.

A "logging tool" is an instrument that is moved in a well to make measurements; for example, while drilling on drill pipe or on wireline while drilling in open or cased holes. The instruments are mounted in a series of carriages, such as cylindrical devices, configured to project into the well, which provide environmental isolation of the instruments.

"Assembly" is the process of tightening the pin and sleeve of a pipe connection together to achieve the union of the two pipe pieces and create a seal between the inside and outside of the pipe.

A "mandrel" is a cylindrical rod or shaft that fits within an outer cylinder. The mandrel may be the main actuator in the packer, which moves the clamping units or "slips" outward to contact the casing. The term mandrel may also refer to a tool that is forced along an expandable tubular to deform it to a larger diameter. Mandrel is a general term used in several types of oilfield installations.

The "wire mesh" of the sand control screen consists of braided metal filaments custom sized and spaced according to the corresponding formation sand particle size distribution. Screen material is usually corrosion resistant alloy (CRA) or carbon steel.

The "Mazeflo ^™ " completion screen is a sand screen with redundant sand control and barrier compartments. Mazeflo ^™ automatically mitigates any mechanical failure of the screen to a localized compartment maze while allowing continuous hydrocarbon flow through undamaged segments. The flow path is deviated such that the flow is diverted to redistribute the incoming flow volume (see, eg, US Patent No. 7,464,752).

"Moyno ^TM pumps" and "progressive chamber pumps" are long cylindrical pumps mounted in a downhole motor that generates rotational torque within the shaft as fluid flows between an external stator and a rotor attached to the shaft. There is usually one more lug on the stator than the rotor, so the force of the fluid flowing to the bit forces the rotor to turn. These motors are usually mounted close to the drill bit. Alternatively, in a downhole pumping arrangement, power can be applied to turn the rotor and thereby pump fluid.

A "packer" is a tool that can be placed in a well on a work string, coiled tubing, production string or wireline. The packer provides fluid pressure isolation of the area above and below the packer. In addition to providing a hydraulic seal that must be durable and withstand harsh environmental conditions, the packer must also resist axial loads due to fluid pressure differentials above and below the packer.

A "packer lockout mechanism" is used to operate a packer such that the packer releases and engages the slips by axial movement of the tubing to which the packer is connected. When engaged, the slips are forced outward into the casing wall, and the teeth of the slips are then pressed vigorously into the casing material. The wireline packer operates by pulling the mandrel to engage the slip's packer placement tool, after which the packer placement tool detaches from the packer and returns to the surface.

"MP35N" is a metal alloy mainly including nickel, cobalt, chromium and molybdenum. MP35N is considered highly corrosion resistant and suitable for harsh downhole environments.

"Paraffin" is the waxy component of certain crude oil hydrocarbons that can deposit on the walls of wellbores and flow lines and thereby cause flow restrictions.

A "pin down connection" is currently the standard drilling configuration in which the sleeve connection is held at the surface by slips while the pin connection faces down during connection assembly.

A "pin up connection" is a drilling tool assembly oriented such that the pin connection is held in the slips at the surface while the connection is made, rather than the standard configuration where the sleeve connection is held by the slips. This reconfiguration may or may not require a change in the thread direction of the connector, ie, left-handed or right-handed.

A "piston" and "piston liner" are cylinders used in a pump to displace fluid from an inlet to an outlet by a corresponding rise in fluid pressure. The bushing is the sleeve within which the piston reciprocates. These pistons are similar to those found in car engines.

A "plunger lift" is a device that moves a tubing string up and down to drain water from the tubing (similar to a pipeline "pigging" operation). With the plunger lift at the bottom of the tubing, the pigging device is configured to block fluid flow and thus push it up in the bore by fluid pressure from below. As the plunger lift moves up the wellbore, it displaces the water by not allowing the water to separate and flow through the plunger lift. At the top of the tubing, the device triggers a change in the configuration of the plunger lift so that it now bypasses the fluid, whereby gravity pulls it down inside the tubing against the upward flow. Friction and wear are important parameters of plunger lift operation. Friction reduces the speed at which the plunger lift device falls or rises, and wear on the outer surface provides clearance that reduces the effective force of the device as it moves up the bore.

"Production unit" is a broad term defined to include any unit related to the drilling, completion, recovery, workover, or production of oil and/or gas wells. A production unit includes any unit described herein for the purpose of oil and gas production. For ease of terminology, fluid injection into a well is defined as production at a negative velocity. Thus, references to the word "produce" will include "inject" unless otherwise indicated.

A "reciprocating seal assembly" is a seal designed to maintain pressure isolation when two devices are displaced axially.

A "roller cone bit" is an earth drilling device equipped with usually three tapered cutting elements to form holes in the earth.

A "rotating seal assembly" is a seal designed to maintain pressure isolation when two devices are rotationally displaced.

A "sand probe" is a small device inserted into a stream to assess the sand content of the stream. If the sand content is high, the sand probe may be eroded.

"Scale" is mineral (eg, calcium carbonate) deposits on pipe walls and other flow equipment that can accumulate and cause flow restriction.

"Service tools" for gravel pack operations include packer transition tools and tailpipes for circulation along the workstring, around the liner and tailpipe, and back to the annulus. This allows drilling fluid to be placed against the formation interval. More generally, a gravel pack repair tool is a set of tools that transports the gravel pack screen to the TD, sets and tests the packer, and controls the flow path of the fluid pumped during the gravel pack operation. The service kit includes a placement tool, an adapter and a seal that seals in the packer orifice. The service tool may include an anti-swipe device and a fluid loss or diverter valve.

A "shock sub" is a modified drill collar having a shock-absorbing spring-like element to provide relative axial movement between the ends of the jar. Vibration subs are sometimes used for drilling into very hard formations where high axial vibration levels may occur.

A "splitter tube" is an outer or inner tube that extends within a sand control screen to divert the gravel pack drilling fluid flow over a long or multi-zone completion interval until a complete gravel pack is achieved. See, eg, US Patent Nos. 4,945,991, 5,113,935 and PCT Patent Publications WO2007/092082, WO2007/092083, WO2007/126496 and WO2008/060479.

"Side pockets" are offset, thick-walled fittings in the tubing that house gas lift valves, temperature and pressure probes, injection line valves, etc.

A "sleeve" is a tubular part designed to fit over another part. The inner and outer surfaces of the sleeve can be circular or non-circular in cross-sectional profile. The inner and outer surfaces may generally have different geometries, ie the outer surface may be cylindrical with a circular cross-section while the inner surface may have an oval or other non-circular cross-section. Alternatively, the outer surface may be oval and the inner surface circular, or some other combination. More generally, a sleeve may be considered to be a generalized hollow cylinder having one or more radii or varying cross-sectional profiles along the axial length of the cylinder.

"Sliding contact" means frictional contact between two bodies in relative motion, whether separated by a fluid or a solid, the latter consisting of particles in a fluid (bentonite, glass beads, etc.) friction device. A part of the contact surface of two bodies in relative motion will always be in sliding state and thus slide.

A "smart well" is a well equipped with devices, instruments, and controls to enable selective flow from specified intervals to maximize production of desired fluids and minimize production of undesired fluids. The flow rate may be adjusted for other reasons, such as controlling groundwater table drop or pressure differential for geomechanical reasons.

"Oil processing" lines are the pipes used to connect pumping equipment to the wellhead for oil processing.

A "subsurface safety valve" is a valve installed in an oil pipeline to shut off flow, and in offshore operations, usually below the seabed. Sometimes these valves are set to close automatically if the speed exceeds a set value, for example in the event of a loss of tightness at the ground.

The "suction rod" is the steel rod that connects the beam pumping unit at the surface to the suction rod pump at the bottom of the well. These rods may be jointed and threaded or they may be continuous rods that are steered like coiled tubing. As the rod reciprocates up and down, there is friction and wear at the point of contact between the rod and the tubing.

A "surface flow line" is a pipe used to connect a wellhead to a production facility or alternatively used to discharge fluids to a pit or flue tower.

A "threaded connection" is a device used to join pipe sections and achieve a hydraulic seal through mechanical interference between interlaced threaded or machined (eg, metal-to-metal seals) components. Assembling or fitting a threaded connection by rotating one device relative to the other. Two pipe pieces may be adapted to be directly threaded together. Or a connector part called a coupler can be screwed onto one pipe, followed by screwing a second pipe into the coupler.

A "tool joint" is a tapered threaded coupling element of pipe, usually made of a special steel alloy, in which a pin and box connection (male and female threads respectively) is secured to either end of the pipe. Tool joints are commonly used on drill pipe, but can also be used on work strings and other OCTG, and they can be friction welded to the end of the pipe.

A "top drive" is a method and apparatus for rotating drill pipe from a drive system located on a cable car that moves up and down rails attached to a drilling rig derrick. Top drive is the preferred method of handling drill pipe because it facilitates simultaneous rotational and reciprocating motion of the pipe and circulation of the drilling fluid. In directional drilling operations, the risk of sticking pipe is generally low when top drive equipment is used.

"Tube" is a pipe installed in a well inside the casing to allow fluid flow to the surface.

A "valve" is a device used to control the flow rate in a flow line. A variety of valve arrangements exist, including check valves, gate valves, globe valves, ball valves, needle valves, and plug valves. The valves can be operated manually, remotely or automatically, or a combination of these. The performance of a valve depends largely on the seal established between the close fitting mechanisms.

A "valve seat" is a static surface against which a dynamic seal rests when the valve is operated to prevent flow through the valve. For example, the flapper of a subsurface safety valve will seal against the valve seat when it is closed.

A "flush line" in sand control operations is a smaller diameter line that runs inside the basepipe after a screen is placed in position across a formation interval. Flush tubing is used to facilitate annular mud flow across the entire completion interval, to backflow during gravel pack treatment, and to exit the gravel pack in the screen-bore annulus.

A "gasket" is typically a flat ring used to prevent leaks, distribute pressure, or secure a joint, such as under the head of a nut or bolt, perhaps in a threaded connection to another component such as a valve. A gasket can be considered a modified form of a sleeve in which the diameter dimension is greater than the axial dimension.

"Wireline" is the cable used to run tools and devices in a wellbore. Wire ropes usually consist of many smaller strands twisted together, but monofilament wire ropes, or "smooth wires," also exist. Wireline is typically deployed on large drums mounted on logging trucks or skid units.

A "work string" is a joined piece of tubing used to perform wellbore operations, such as running logging tools, pulling material from the wellbore, or performing cement grouting operations.

(Note: Part of the above definition comes from "Dictionary for the Petroleum Industry", Third Edition, University of Texas at Austin, Department of Petroleum Extension, 2001)

detailed description

All numerical values in the detailed description and claims herein are modified by the value indicated by "about" or "approximately" and take into account experimental error and variations that would be expected by those of ordinary skill in the art.

Reconfiguring the device to utilize sleeves at designated locations such as contact points between two or more bodies facilitates the use of this low friction technique. The use of the coating on the sleeve element provides a small part that can be easily placed into a manufacturing apparatus or chamber to apply the coating, with improved economics. Removable sleeves can be more easily replaced within the context of ongoing field operations with small components that can be easily moved between the manufacturing plant and field locations. Also, with respect to metallurgical considerations, a wider selection of coating and substrate materials is available for these devices that may not be the primary stress components of oil and gas production operating systems. Coatings applied at elevated temperatures would cause additional manufacturing complications, since such manipulations could adversely affect the heat treatment of such materials.

Additionally and alternatively, the design configuration of the bottom hole equipment may be modified to facilitate the use of the sleeve. For example, the orientation of a tool joint of a drill string or work string may optionally be altered so that an externally threaded pin connection rather than an internally threaded box connection remains at the surface during tool joint connection operations. This reconfiguration facilitates the use of the sleeve, since the sleeve does not drop down the hole or fall to the ground when the connection is broken during the tripping operation of the pipe. With this design, no tightening of the sleeve element as specified in US Patent No. 7,028,788 ("WearSleeve") is required.

In one embodiment of the present disclosure, the axis of the sleeve element may be substantially parallel to the axis of the cylinder to which it is approached. The sleeve element may be free in one or more degrees of freedom or the sleeve element may be fixed relative to a proximal object (post or body) using a suitable attachment mechanism or geometric arrangement to provide constraint. Typically, the sleeve element will be constrained to move at least coaxially with the proximal object, but the sleeve element may be rotationally constrained or free to rotate. The use of an elliptical or non-circular cross-section at the interface between the sleeve and the proximal object would be one of many possible means of limiting rotation of the sleeve with the proximal object. Also, the sleeve element may be inside or outside the proximal object depending on the particular characteristics and use of the sleeved oil and gas production device.

Sleeves can 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 combination of the above production. The sleeve material may be subjected to localized, lateral loads, but not normally to the generally larger axial loads experienced by the body it approaches. Thus, the sleeve material and geometry are not limited by the strength and toughness requirements compared to the body. This allows material selection for the sleeve based on, but not limited to, conditions such as the type of coating and its processing temperature.

Similar reconfigurations to other oil and gas production devices are possible within the scope of the present disclosure to facilitate the use of sleeves that may be coated with already approved materials.

Disclosed herein are coated sleeved oil and gas well generation devices and methods of making and utilizing the coated sleeved devices. The coatings described herein provide significant performance improvements for the various oil and gas well devices and operations disclosed herein. Figure 1 shows a general oil and gas well production system for which application of coatings to certain of the sleeved production devices described herein may provide improved performance of these devices. FIG. 1A is a schematic illustration of a land-based drilling rig 10 . FIG. 1B is a schematic illustration of a drilling rig 10 directionally drilling through sand 12 , shale 14 , and water 16 into an oil field 18 . 1C and ID are schematic diagrams of production well 20 and injection well 22 . FIG. 1E is a schematic illustration of perforation gun 24 . FIG. 1F is a schematic illustration of the gravel pack 26 and the screen liner 28 . Without loss of generality, different coatings of the invention may be preferred for different well production devices, and different types of sleeves may be appropriate for different well production devices. A broad review of production operations generally shows the range of possible field applications for coated sleeved devices to mitigate friction, wear, erosion, corrosion and deposition.

Methods of coating such sleeved devices disclosed herein include applying a suitable coating to a portion of the inner sleeve surface, outer sleeve surface, or combination thereof that will be subject to friction, wear, corrosion, erosion, and/or deposition. Applying a coating to at least a portion of the sleeve surface exposed to contact with another solid body or with a fluid stream, 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 coated tape The wear resistance of the sleeve device is at least 3 times that of the uncoated device; and/or the surface energy of the coating is less than 1 J/m ² . There are techniques for selecting a suitable coating from the disclosed coatings and designing a suitable sleeve element for a particular application to maximize the technical and economic advantages of this technology.

US Patent Application No. 12/583,292, filed August 18, 2009, which is hereby incorporated by reference in its entirety, discloses the use of ultra-low friction coatings on drill stem assemblies used in oil and gas drilling applications. US Patent Application No. 12/583,302, filed August 18, 2009, which is hereby incorporated by reference in its entirety, discloses the use of coatings on oil and gas well production devices.

Drill stem assemblies are 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 that includes a cylindrical body. In the case of drill pipe, the actual drill pipe assembly is the inner cylinder in sliding contact with the casing or open hole, the outer cylinder. These devices may have varying radii and may alternatively be described as comprising a plurality of bordering cylinders of varying radii. As described below, several other situations exist in oil and gas well production operations where cylindrical bodies either come into sliding contact due to relative motion or remain stationary after contact with the fluid stream. By considering the relevant problems to be solved, by evaluating the contact or flow problems to be solved to mitigate friction, wear, corrosion, erosion or deposits, and by judiciously considering how the sleeve can be designed into the configuration of the device and be used for maximum utilization and benefit. Coatings of the present invention may be advantageously used in each of these applications when the coatings are applied to these sleeve elements to achieve an advantageous coated sleeved oil and gas production device.

There are many examples of oil and gas well production devices that offer opportunities for beneficial use of coated sleeved devices, as described in the background section, including: having low friction for initial installation and for wear, corrosion resistance and stationary sleeved devices with sleeved elements coated for resistance to erosion and deposition on external or internal surfaces; and sleeved bearings, bushings and other geometries in which the sleeved elements are coated, Used to reduce friction and wear and resist corrosion and erosion.

In each case, there may be primary and secondary motivations for using coated sleeved devices to reduce friction, wear, corrosion, erosion and deposition. The same device may include more than one sleeve element with different coatings applied to address different coating design aspects, including the problem to be solved, the techniques available for applying the coating to the sleeve element, and the compatibility with each coating design. The economics associated with the layer type. There will likely be many trade-offs and compromises that govern the final design of the sleeve element and the choice of coatings to be applied.

Overview of the use and associated benefits of coated sleeved devices:

Among the wide range of operations and equipment required during the various stages of preparation and production of hydrocarbons from a wellbore, there are a variety of prototype applications occurring in various environments. These applications can be viewed as various geometries of bodies in sliding mechanical contact with solid object surfaces and fluid flows interacting with solid object surfaces. The design of these components may be adapted to incorporate coated sleeve elements to reduce friction, wear, erosion, corrosion and deposits. In this sense, the components become "coated sleeved oil and gas well production devices". A variety of specific geometries and exemplary applications are listed below, but those skilled in the art will appreciate a wide range of applications for coated sleeved devices and this list does not limit the scope of the inventive methods disclosed herein.

A. Coated sleeved cylindrical body in sliding contact due to relative motion:

In applications that are ubiquitous throughout production operations, two cylindrical bodies are in contact and friction and wear occur as one body moves relative to the other. The body may comprise a plurality of cylindrical segments contiguously positioned at different radii, and the cylinders may be coaxially or non-coaxially positioned. The component design may be adapted to place a sleeve element at the point of contact between the two cylindrical bodies. The sleeve element may be coated on at least a portion of the inner sleeve surface, the outer sleeve surface, or some combination thereof to beneficially reduce contact friction and wear. The sleeve element may optionally be removable and may subsequently be maintained or replaced as required and appropriate for the application of the device.

For example, designing sleeve elements for tool joints of drill pipe or work strings and coating such sleeve elements can be an effective way of using coatings to reduce contact friction between drill pipe and casing or open hole. For casing, tubing, and suction rod strings, the pipe coupling is a sleeve element that may have a coating 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 beneficial to adapt the tool to have one or more coated sleeve elements comprising the largest outer diameter of the device to Reduces wear and friction due to contact with the tubing string.

An exemplary list of the applications follows:

Drill pipe can be picked up or unwound, causing longitudinal motion and can be rotated within casing or open hole. Friction and device wear increase with increasing well inclination, with increasing local borehole curvature, and with increasing contact load. These frictional loads cause significant drilling torque and drag that must be overcome by the drill rig and drill string assembly (see Figure 2). Figure 2A shows deflection occurring in a drill string assembly 30 in a directional or horizontal well. FIG. 2B is a schematic illustration of drill pipe 32 and tool joint 34 with threaded connection 35 . In this figure a coated sleeve element 33 is shown at the pin connection. FIG. 2C is a schematic illustration of the drill bit and bottom hole assembly 36 . Figure 2D is a schematic illustration of the sleeve 38 and the tool adapter 39 showing the contact that occurs between the two cylindrical bodies. The friction-reducing coatings applied to the sleeve elements disclosed herein can be used to reduce friction and wear between the two components as the tool joint 39 rotates within the casing 38, and also reduce the wear and tear required to drill a lateral well. The torque required to turn the tool joint 39.

Bottom hole assembly (BHA) devices sit beneath the drill pipe on the drill stem assembly and may experience similar friction and wear, and thus the coatings disclosed herein may provide a reduction in these mechanical problems (see FIG. 3 ). In particular, the coatings disclosed herein applied to BHA devices can reduce friction and wear at the point of contact with the open hole and extend tool life. The low surface energy of the coatings disclosed herein can also inhibit adhesion of formation cuttings to tools and can also prolong corrosion and erosion limits. It also reduces the tendency to stick differently. Figure 3A is a schematic illustration of a milling cutter 40 used in a bottom hole assembly arrangement. Figure 3B is a schematic illustration of a drill bit 41 and reamer 42 used in a bottom hole assembly arrangement. Figure 3C is a schematic illustration of a reamer 44 used in a bottom hole assembly arrangement. In this figure a coated sleeve element 43 is shown. Figure 3D is a schematic illustration of a stabilizer 46 used in a bottom hole assembly arrangement. Figure 3E is a schematic illustration of a sub 48 used in a bottom hole assembly arrangement.

Drill strings operate within subsea riser systems and may cause wear to the riser due to drilling operations. Vibration of the riser due to ocean currents can be slowed by the coating and the presence of marine growth can be inhibited, further reducing drag associated with flowing currents. Referring to Figure 4, the use of coatings disclosed herein on the riser pipe exterior 50 can be used to reduce friction and vibration due to ocean currents. Additionally, the use of coatings disclosed herein on the sleeved inner bushing 52 and other contact locations that may be protected by a coated sleeved device can be used to reduce friction and wear. A coated sleeve element 53 may be suitable for riser connections and is shown in this figure.

The plunger lift removes water from the well by running up and down the tubing string. Both the plunger lift outer diameter and the tubing inner diameter can 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 of plunger lift operation and increase the applicable range of this technology. Reducing the wear on both the tubing and the plunger lift will increase the time interval between required maintenance. From an operational standpoint, reducing wear on the inner diameter of the tubing is highly desirable. Also, it may be beneficial to coat the interior surfaces of the plunger lift device. A coated sleeve element can be incorporated into the outside of the plunger lift tool, where the outside diameter of the sleeve element will be nearly equal to the inside diameter of the tubing in which the device is to be Sliding inside the string. Depending on the plunger lift design, these sleeve elements will be replaced in the field and return the tool to service. Optionally, the entire surface area of the plunger lift may be coated to reduce friction and wear. In the bypass state, if the flow resistance is reduced by the coating on the inside of the tool, fluid will flow through the tool more easily, allowing the tool to descend faster.

The completion slide sleeve may be moved axially, such as by striking the coiled tubing to displace the cylindrical sleeve upward or downward relative to the tool body, which may be cylindrical. These sleeves are susceptible to friction, wear, erosion, corrosion and adhesion due to damage from formation material and accumulation of scale and sediment. Coating certain parts of the sleeve elements to allow movement within these sliding sleeve systems will help ensure that the sliding sleeve device will not stick when the sliding sleeve device needs to move.

Suction rods and Corod ^TM tubing are used in oil pumps to pump oil to the surface in low pressure wells, and they can also be used to pump water out of gas wells. Friction and wear occur continuously as the rod moves relative to the tubing string. The reduction in friction may enable the selection of smaller pumping units and reduce power requirements for well pumping operations (see Figure 5). Referring to FIG. 5A , the coated sleeves disclosed herein can be used at contact sites of rod pumping devices including, but not limited to, as a suction rod coupler with a sleeved device attached to a suction rod 62, Suction rod guide 60 , suction rod 62 , tubing packer 64 , downhole pump 66 and perforation 68 . Referring to FIG. 5B, the coatings disclosed herein can be used on polishing rod clamp 70 and polishing rod 72 to provide a smooth durable surface and a good seal. A coated sleeve element 71 is shown at the suction rod seal to provide a low friction tight seal. FIG. 5C is a schematic illustration of a suction rod 62 in which a coating disclosed herein may be used to prevent friction and wear and used on a threaded connection 74 . The suction rod coupler 73 may be coated on its own right side as a sleeve element, or it may be adapted for use with an outside coated sleeve to provide a low friction durable surface in contact with the tubing string, which Reciprocating movement in the tubing string.

Sleeved devices in pistons and/or piston liners in pumps for drilling fluids on drilling rigs and pumps for production fluids in well production activities may be coated to reduce friction and wear, enabling improved pump performance and extend unit life. Because some equipment is used to pump the acid, the coated sleeve liners also reduce corrosion and erosion damage to these devices.

Expandable tubulars are typically run in a bore, supported with a suspension assembly and then expanded by running a mandrel through the pipe. Coating the surface of the mandrel can greatly reduce mandrel loads and allow expandable tubular applications at more inclined wells or greater expansion ratios than would otherwise be possible. The mandrel can be set to have a coated sleeved device at the location of the highest contact stress. If removable, these coated sleeves would allow for long mandrel tool life and possible field remediation. The speed and efficiency of the expansion operation can be improved by a significant reduction in friction. A mandrel is a tapered cylinder and can be considered to comprise a bordering cylinder of varying radii; alternatively, a tapered mandrel can be considered to have a complex geometry.

Control lines and conduits may be internally coated for the benefit of flow resistance and corrosion/erosion reduction. Glass wool fibers can be pumped down with reduced resistance within coated conduits and steering fittings.

Tools that operate in wellbores are typically cylindrical bodies or bodies that include bordering cylinders of varying radii that operate on wireline or rigid tubing in casing, tubing, and open hole. Frictional resistance increases with increasing borehole inclination or local borehole curvature, making operation of such tools unreliable on wireline. A coated sleeved device at the contact surface allows the tool to be reliably operated on wireline at large inclinations or to reduce the risk of drilling in horizontal wells with coiled tubing, tractors, or down pumping devices. Lower the force to push the tool. The list of such tools includes, but is not limited to: logging tools, perforating guns, and packers (see Figure 6). Referring to FIG. 6A , the coatings disclosed herein may be used on the outer surface of a caliper logging tool 80 to reduce friction and wear with the open hole 82 or casing (not shown). The part 83 with the largest diameter can be sleeved with a low friction coated sleeve to allow the tool to run in the hole with less drag and wear. Referring to FIG. 6B, the coatings disclosed herein can be used on the outer sleeved surface 85 of the sonic logging probe 84, including but not limited to the signal transmitter 86 and signal receiver 88, to reduce interference with the casing 90 or in the Friction and wear in bare holes. Referring to Figures 6C and 6D, the coatings disclosed herein can be used on the outer coated sleeved surface 93 of the packer tool 92 and the sleeve 95 of the perforating gun 94 to reduce friction and wear with the open hole. The low surface energy of the coating will prevent the adhesion of the formation to the tool and also extend the limits of corrosion and erosion.

Wire rope is an elongated cylindrical body that operates in casing, tubing and open holes. In more detail, each strand is a cylinder, and the stranded strands are bundles of non-axial cylinders, which together form the effective cylinder of the wire rope. There is friction at the contact site between the wire rope and the bare hole and therefore coating the wire rope with a low friction coating will enable operation with reduced friction and wear. Braided rope, multicore conduits, single core conduits, and well test slicklines can all be advantageously coated with a low friction coating (see Figure 7). Referring to FIG. 7A , the coatings disclosed herein may be applied to a steel wire rope 100 by applying to the rope 102 , individual strands 104 of the rope, or bundles 106 of strands. A pulley type device 108 as seen in Figure 7B may be used to run logging tools delivered by wireline 100 into casing, tubing and open hole. Pulley arrangements can advantageously use coated sleeves in areas of pulleys and bearings that are subject to load and wear due to friction.

Casing centralizers and contact rings for downhole tools are sleeved devices that can be coated to reduce frictional resistance in placing these devices in the borehole and providing bottomhole movement especially at higher borehole inclination angles .

B. Predominantly stationary coated cylindrical body:

There are diverse applications of coated sleeved sections for the exterior, interior or both of cylindrical bodies such as pipes or modified pipes, mainly to resist erosion, corrosion and wear, But also for reducing friction in fluid flow. The cylindrical body may be coaxial, bordering, non-axial, non-bordering, or any combination thereof, wherein the sleeve is located in a proximal position relative to the inner or outer surface of the cylindrical body. In these applications, the coated sleeved cylindrical device may be substantially stationary for long periods of time, but perhaps a secondary benefit or application of the coated sleeve is to reduce the Friction load.

An exemplary list of such applications follows:

Perforated, slotted, or screened substrates for sand control are often subject to erosion and corrosion damage during completion and recovery treatments such as gravel pack or frac pack treatments, and over the productive life of the well . For example, coatings obtained using the method of the present invention will provide a larger internal diameter for flow and reduce flow pressure drop relative to thicker plastic coatings. In another example, corrosion-generated fluids may attack material and cause material loss over time. Also, highly productive formation intervals may provide fluid velocities high enough to cause erosion. These fluids may also carry solid particles, such as fines or formation sand, which tend to render completions ineffective. Deposits of bitumen, paraffin, scale and hydrate may also form on completion equipment such as base pipe. Coatings can provide benefits in these situations by reducing the effects of friction, wear, corrosion, erosion and deposition. (See Figure 8) Certain coatings for screen applications have been disclosed in US Patent No. 6,742,586 B2. In this application, the use of a coated sleeved device facilitates the installation of the sand control device due to reduced friction and wear. Coated sleeved units can also be used as "wear joints" where higher sand and proppant particle velocities can be expected to reduce the life of the sand screen material.

Flush lines, shunt lines, and maintenance tools used in gravel pack operations can be coated internally, externally, or both to reduce erosion and flow resistance. The solids-entrained fluids targeted by the gravel pack are pumped through these devices at high rates. Sleeved devices may be used at specific locations in these tools to protect the body of the device from erosion due to sand and proppant flow.

Abrasion resistant joints may advantageously be coated for greater resistance to erosion caused by high velocity collisions of fluids and solids. Coated sleeved devices can be advantageously used at specific locations of the abradable joint where the greatest amount of abradable damage is expected.

To reduce friction and resist corrosion and erosion, a thin metal mesh can be coated. The coating process may be applied to the individual cylindrical strands before weaving or before the collecting web after weaving has been performed, or both, or in combination. A screen can be thought of as comprising many columns. The strands can be drawn through the coating device to achieve application of the coating over the entire surface area of the rope. Coating applications include, but are not limited to: sand screens placed in well completion intervals, Mazeflo ^TM completion screens, sintered screens, wire wound screens, shaking screens for solids control and as oil and gas Other screens for well production equipment. The coating can be applied to at least a portion of the filter media, the screen substrate pipe, or both. (See Figure 8) Figure 8 illustrates an exemplary application of the coatings disclosed herein on screens and substrate pipes. In particular, the coatings disclosed herein may be applied to the screen 110 and the slotted liner of the base pipe 112 as shown in FIGS. 8A and 8B to prevent corrosion, erosion and deposition thereon. The close-up detail of Figure 8A shows the coated sleeve element 111 on the outside of the screen to allow it to slide downhole with reduced frictional resistance. The coatings disclosed herein may also be applied to screens in the shale shaker 114 of a solids control apparatus as shown in Figure 8C. Coated sleeved devices can be used in various ways with these devices described above to reduce friction at wellbore contact during installation and to reduce friction in the specific location where the sleeve is applied during oil recovery and production. Erosion damage caused by sandstone and proppant flow.

Coated sleeved devices reduce material hardness requirements and mitigate the effects of corrosion and erosion on certain devices and components, enabling the use of lower cost materials as stellite, carbide, MP35N, high alloy materials and Alternatives to other expensive materials chosen for this purpose.

C. Plates, disks and complex geometries:

There are many coated sleeved device applications that can be considered for non-cylindrical devices such as plates and disks or for more complex geometries. An exemplary application of this geometry of the disc is a gasket device that can be coated on one or both sides to reduce friction during device operation. The benefits of coatings can arise from the reduction of sliding contact friction and wear caused by relative motion with respect to other devices or possibly from the reduction of corrosion, erosion and deposition from interaction with fluid flow, or in many cases through both combination is realized. These applications can benefit from the use of coatings as described below.

An exemplary list of such applications follows:

Chokes, valves, seats, seals, ball valves, inflow control devices, smart well valves and annular isolation valves can beneficially use coated components such as sleeves and gaskets to reduce erosion, corrosion and destroy. 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, valve 113, blowout preventer 115, wellhead 114, downpipe cock 116, and gas lift valve 118 may use coated Sleeves and gaskets 117 to provide resistance to friction, erosion and corrosion in high speed components, and the smooth surfaces of these coated devices provide enhanced sealability. In Figure 9E, a coated sleeve 119 can be used to allow the gas lift device to easily enter the side pocket and seal properly. 10A, 10B and 10C, the choke 120, the orifice meter 122 and the turbine meter 124 can have a coated sleeve and gasket 123 with coatings disclosed herein to provide resistance to friction, Restrictors and other components (eg, impellers and rotors) for further resistance to erosion and corrosion. By using the same or different coatings on different parts of a production device to reduce friction and wear, other surface areas of the same production device can be protected by coated sleeves and gaskets.

Seats, chokes, valves, side bags, mandrels, packer slips, packer cleats, etc. may beneficially use coated sleeve and gasket arrangements with low friction coatings.

Subsurface safety valves are used to control flow where there is a risk of loss of surface containment. These valves are routinely used in offshore wells to increase operational integrity and are often required by regulations. Improvements in the reliability and availability of subsurface safety valves provide significant benefits to operational integrity and can avoid costly workover operations in the event of valve test failures. In moving valve arrangements, enhanced sealability, resistance to corrosion, erosion and deposits, and reduced friction and wear can be very beneficial for these reasons. The use of coated sleeves and gaskets in subsurface safety valves will improve their operability and achieve the benefits described above.

Gas lift and chemical injection valves are commonly used in tubing strings to enable fluid injection, and coating portions of these devices will enhance their performance. Gas lift is used to reduce the static head and increase flow from the well and, for example, to inject chemicals to inhibit the formation of hydrates or scale in the well that would impede flow. The use of coated sleeves and gaskets in gas lift and chemical injection valves will improve their operability and achieve the benefits described above.

Elbows, tees and couplings can be internally coated to reduce fluid friction and prevent scale and deposit build-up. In these applications, coated sleeved devices may be used in specific locations of high erosion, such as in bends, intermediate joints, tees, and other areas of fluid mixing and wall impingement of entrained solids.

Ball bearings, sleeve bearings and journal bearings of rotating equipment can be coated to provide low friction and wear resistance and to achieve longer bearing unit life.

Anti-friction bushings are available with coated sleeves for reduced friction and wear and for improved handling.

Coated sleeves in dynamic metal-to-metal seals can be used to augment or replace elastomers in reciprocating and/or rotary seal assemblies.

Moyno ^TM and progressive chamber pumps consist of a vaned rotor turning within a fixed stator. Coated sleeved devices in these components will enable improved operation and increased pump efficiency and durability.

Impellers and stators in rotating pump devices may include coated sleeved devices for resistance to erosion and wear, and for durability in the presence of fine solids in the flow stream. Such applications include submersible pumps.

Coated sleeved devices for drilling fluid solids control in centrifugal devices enhance the effectiveness of these devices by preventing clogging of centrifuge discharges. The life of the centrifuge can be extended by the erosion resistance provided by the coated sleeve elements.

Springs in coated tools can have reduced contact friction and long life reliability. Examples include safety valves, gas lift valves, shock mounts and jars.

Well logging tool devices may utilize coated sleeved devices for improved operations including deployment of arms, coring pipes, fluid sampling bottles and other devices into the wellbore. If a coating is applied, a device that protrudes from the tool and then retracts into the tool may be less prone to clogging due to friction and solid deposits.

Fishing equipment including, but not limited to, casing washpipes, grapples, and slip overshots may beneficially use coated sleeves to facilitate locking onto or removing separate components of the equipment from the wellbore or " salvage". Low-friction entry into the slip overshot pipe is facilitated by a coated socket, and a hard coating on the grapple improves tool bite. (See FIG. 11 ) In particular, referring to FIG. 11A , coatings disclosed herein may be applied to casing wash piping 130 , casing washing piping connector sleeves 132 , swivel shoes 134 , and fishing gear to reduce entry of anchor jacks 136 into casing washing. String friction. A tapered and coated sleeve 133 may be used to ease anchor jack entry into the casing wash line. Additionally, referring to FIG. 11B , coatings disclosed herein may be applied to the grapples 138 to maintain material hardness for good grip.

D. Threaded connection:

High-strength piping materials and specialty alloys in oilfield applications can be prone to galling, and threaded connections can be beneficially coated to reduce friction and increase surface hardness during assembly of the connection and to enable repeated use of the pipe and connection without No rethreading required. Improves sealing performance without risk of galling by achieving higher contact stress.

Pins for casing, tubing, drill pipe, drill collars, work strings, surface flow lines, stimulation process lines, threads for connecting bottomhole tools, subsea risers and other threaded connections involved in production operations and/or box threads may be beneficially coated with the low friction coatings disclosed herein. The threads may be coated alone or in combination with techniques currently used to improve joint assembly and galling resistance, including shot peening and cold rolling of the threads, and possibly, but less likely, chemical treatments of the threads. (See FIG. 12 ) Referring to FIG. 12A , pin 150 and/or sleeve 152 may be coated with the coatings disclosed herein. Referring to FIG. 12B , threads 154 and/or shoulder 156 may be coated with the coatings disclosed herein. A coated sleeve element 153 is shown at the connecting pin. In FIG. 12C , threaded connections (not shown) of threaded tubing 158 may be coated with coatings disclosed herein. In Fig. 12D, galling 159 of threads 154 can be prevented through use of coatings disclosed herein. The coating in this case may be applied to one or two sets of threads in a threaded connection.

E. Exemplary Sleeve Configurations for Drilling Applications

Segments of drill pipe are screwed together and unscrewed as the drill string is extended or shortened during the drilling process. Some modern rigs do this with automated equipment called a "fabrication connection". As shown in Figure 13A, slips 171 are set in the rig floor or rotary table 173 to hold a drill string 175, the tubing is unscrewed, and the connection is "broken". The disassembled tubing held by the rig jack may be added to the string as the tubing runs through the borehole, or may be removed as the tubing is withdrawn from the borehole. In Figure 13A, the connector 177 held by the slips is a tool joint socket connector.

Figure 13B shows the coated sleeve element 181 on the pin 179 of the connector oriented according to the standard "pin down" convention. Note that the gravity vector 180 points down. It will be understood that this is inconvenient from the point of view of the fact that when the connection is broken and the separated pipe is removed, the sleeve, if not attached in some way, will fall to the ground or down the hole. Down. In US Patent 7,028,788, Strand solves this problem by threading a sleeve and pin connection such that the sleeve is secured with the pin during connection making and breaking.

It will be appreciated that certain problems may exist with threaded sleeve systems because the threads specified in US Patent 7,028,788 are exposed outside the drill pipe and in close proximity to the formation and drilling fluid during the drilling process. The potential for these threads to be compromised or have formation material trapped in the threads would be significant. Additionally, there will be additional costs associated with the manufacture and maintenance of the threads on both the sleeve and pin. If the thread of the sleeve or pin connection is damaged, the corresponding part of the device must be repaired before subsequent use.

An exemplary alternative is to use a "pin up" configuration as shown in Figure 13C. With the pin 179 facing upwards, the sleeve 181 can be placed directly on the pin when the connection is made and remains in place when the connection is broken. Again, gravity vector 180 is pointing downwards 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 are used, one non-limiting means of preventing rotation of the sleeve is to use a key or slot, or may be The sleeve on the pin connection provides an elliptical profiled inner sleeve surface and corresponding cross-sectional area.

Figure 13D shows an enlarged view of the inner profile configuration of the elliptical sleeve. Outer sleeve surface 183 has a circular cross-section, such as pinned inner surface 188 . Usually, the thread of the pin is made on a tapered conical section. However, in the low stress region of the pin above the threads, the oval cross-section 186 is machined to match the dimensions of the sleeve inner surface cross-section 184 with suitable tolerances to allow the sleeve to slide over the threads onto the pin body . Careful analysis is required to ensure that there is sufficient material strength in the sleeve so that it does not deform and the pin strength is not compromised under the expected torsional loads. Typically, material can be removed down to the bevel diameter without compromising pin strength. Recognizing that the duct will turn in one direction, asymmetric profiles can be considered and other alternative cross-sectional profiles can be devised without departing from the spirit of the present disclosure.

Without departing from the basic idea of using coated sleeve elements to take advantage of the advantageous low friction material while drilling, it is conceivable to attach the sleeve to the proximal region of the drill pipe using a pin connection, sleeve connection or other Alternative way of attaching to the tool adapter.

Drilling Conditions, Applications and Benefits:

Detailed examination of the drilling process, an important aspect of production operations, can help identify several challenges and opportunities for specific applications in which coated sleeved devices are beneficially used during well production.

Deep wells for oil and gas exploration and production are drilled using rotary drilling systems that form the borehole with the aid of rock cutting tools, or drill bits. The torque that drives the bit is typically generated at the surface by a motor with a mechanical gearbox. With the aid of this transmission, the motor drives the turntable or the top drive unit. The medium that transmits energy from the surface to the drill bit is the drill string, which mainly consists of drill pipe. The lower part of the drill string is the Bottom Hole Assembly (herein abbreviated as BHA), which consists of drill bits, drill collars, stabilizers, surveying tools, lower reamers, motors and other devices known to those skilled in the art. The combination of drill string and 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 bottom hole assembly is also referred to herein as a drill pipe assembly. In other configurations, the cutting elements near the bottom end of the casing comprise a "drilling while casing" system. The coated sleeved oil and gas well production devices disclosed herein provide particular benefits in such downhole drilling operations.

With today's advanced directional drilling techniques, multiple lateral wellbores can be drilled from the same initial wellbore. This may mean drilling at much longer depths and using directional drilling techniques, for example, by using a rotary steerable system (abbreviated herein as RSS). While this offers primarily 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 vertical deflection, or inclination (the angle formed with the vertical), can be as large as 90°, which are commonly referred to as horizontal wells. During drilling operations, the drill string assembly tends to sit against the sidewall of the borehole or well casing. In directional wells, this tendency is greater due to gravity. As the length and/or deflection of the drill string increases, the overall frictional drag created by the rotating drill string also increases. To overcome this increase in frictional drag, additional power is required to rotate the drill string. The resulting friction and wear affect drilling efficiency. The measured depth that can be achieved in these situations may be limited by the available torque capacity of the well and the torsional strength of the drill string. More efficient solutions need to be found to increase equipment life and drilling capacity using existing rigs and drive trains to extend the lateral reach of these operations.

The deep drilling environment, especially in hard rock formations, causes severe vibration of the drill pipe assembly, which can lead to decreased bit penetration rates and premature failure of downhole equipment. The drill stem assembly vibrates axially, torsionally, laterally, or generally in a combination of these three fundamental modes, ie, associated vibrations. The use of the coated sleeved devices disclosed herein can reduce the torque required to drill wells and also provide resistance to torsional vibration instabilities, including slip adhesion vibration functions of the drill string and bottom hole assembly abnormal. The reduced drill string torque may allow the drilling operator to drill the well at a higher rate of penetration (ROP) than when using conventional drilling equipment. A coated sleeved device in a drill string disclosed herein prevents or delays the onset of drill string buckling, including helical buckling, and prevents vibration-related drill stem assembly failure and associated non-productivity during drilling operations. time.

The drill string includes one or more selected from the group consisting of drill pipe, tool joints, transition pipe between the drill string and bottom hole assembly including tool joints, heavy drill pipe including tool joints and wear pads, and combinations thereof device. The bottom hole assembly includes one or more devices selected from but not limited to: stabilizers, variable diameter stabilizers, back expansion reamers, drill collars, flexible drill collars, rotary steerable tools, roller reamers, Damping joints, drilling fluid motors, logging while drilling (LWD) tools, measuring while drilling (MWD) tools, coring tools, lower reamers, reamers, centralizers, turbines, bent housings, bent motors , drilling jars, acceleration jars, adapters, lower jars, torque reduction tools, floating subs, fishing tools, fishing jars, casing wash pipes, logging tools, survey tool joints, any of these devices A non-magnetic counterpart and its associated external connection means.

The coated sleeved oil and gas well production devices disclosed herein can be used in drill pipe assemblies where the downhole temperature ranges from 20 to 400°F with a lower limit of 20, 40, 60, 80 or 100°F and an upper limit of at 150, 200, 250, 300, 350 or 400℉. During rotary drilling operations, the drilling rotational speed 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 200RPM. Furthermore, during rotary drilling operations, drilling fluid 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.

In one form, a coated sleeved oil and gas well production device disclosed herein with a coating on at least a portion of the exposed outer surface provides at least 2 times, 3 times, 4 or 5 times the abrasion resistance. In addition, the coated sleeved oil and gas well production devices disclosed herein are compared when used on a drill stem assembly with the coating on at least a portion of the surface compared to when using an uncoated drill stem assembly for rotary drilling A reduction in casing wear is provided. Furthermore, 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 make the casing Wear is reduced by at least a factor of 2, or a factor of 3 or a factor of 4 or a factor of 5.

Coatings on the drill stem assemblies disclosed herein may also eliminate or reduce the velocity reduction of the coefficient of friction. More specifically, rotary drilling systems used to drill deep boreholes for hydrocarbon extraction and production typically experience severe torsional vibrations that cause an instability known as "slip sticking" vibration, characterized by (i) sticking an additional phase, in which the drill bit or BHA slows down until it stops (relative slip velocity is zero), and (ii) a slip phase, in which the relative slip velocity of the downhole component accelerates rapidly to a rate faster than the rotational velocity (RPM) imposed by the drill rig at the surface ) for much larger values. This problem is particularly acute for drag bits consisting of stationary blades or cutters mounted on the face of the bit body. The non-linearity in the law of friction nature causes the instability of the stable friction-slip which overcomes the slip-adhesive oscillation. Therefore, this leads to complicated problems.

The velocity weakening characteristic, represented by a decreasing coefficient of friction with increasing relative slip velocity, can lead to torsional instability that triggers stick-slip vibrations. Slip instability is a problem in drilling because it is one of the main factors limiting the maximum penetration rate. In drilling applications, it is advantageous to avoid stuck slip conditions because they cause vibration and wear, including associated vibrations that start to break. By reducing or eliminating velocity dampening properties, the coatings on drill string components disclosed herein enable the system to enter a continuous slip regime where the relative slip velocity is constant and does not oscillate (avoid sticking slips) or exhibit local RPM rapid acceleration or slow down. Even with existing methods of avoiding slip sticking by using lubricant additives or tablets to the drilling fluid, slip sticking may still occur under high normal loads and small sliding velocities. The coating on the drill stem assembly disclosed herein ensures that there is also no slip sticking motion under high normal loads.

Another drilling problem is common in intervals that primarily contain shale formations. “Bit balling” can occur when shale cuttings adhere to the bit cutting face due to differential fluid pressure, significantly reducing drilling efficiency and ROP. Shale cuttings adhere to BHA devices such as stabilizers causing drilling inefficiencies. These problems are exacerbated by the use of water-based drilling fluids, which may be preferred for cost and environmental reasons.

Drilling vibration and bit balling are two of the most common causes of drilling inefficiency. These inefficiencies can be manifested as ROP limits or "Break point". This limit is schematically shown in FIG. 14 . It has been recognized in the drilling industry that drill pipe vibration and bit balling are the two most challenging factors limiting penetration velocity. The coated sleeved devices disclosed herein can be applied to drill stem assemblies to help alleviate these ROP limits.

In addition, the coated sleeved devices will improve the performance of drilling tools, particularly bottom hole assemblies for drilling in formations containing clay and the like. These coating materials provide thermodynamically low energy surfaces, eg, non-wettable surfaces for downhole devices. The coatings disclosed herein are suitable for oil and gas drilling in clay-rich regions, such as deep shale drilling with high clay content using water-based drilling fluids (abbreviated herein as WBM), to prevent balling of bottom hole assemblies.

Furthermore, the coated sleeved devices disclosed herein are capable of simultaneously reducing contact friction, balling, and reducing wear when applied to drill string components without sacrificing casing durability and mechanical integrity. Thus, the coatings 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 attenuation of frictional properties. Thus, a drill stem assembly provided with the disclosed coated sleeved arrangement herein provides a low friction surface with the benefit of both reduced slip stick vibration and parasitic torque, further enabling ultra-large displacements drilling.

The coated sleeved devices disclosed herein for drill stem assemblies provide the following exemplary, non-limiting advantages: i) mitigation of slip sticking vibrations; ii) reduction of torque and drag for extended large displacement displacement of the well; and iii) mitigation of balling of the drill bit and other bottom hole assemblies. These advantages, together with minimization of parasitic torque, can lead to significant improvements in drilling penetration speed and durability of bottom hole drilling equipment, thereby also helping to reduce non-productive time (herein abbreviated as NPT). The coatings disclosed herein not only reduce friction, but also withstand adverse downhole conditions requiring chemical stability, corrosion resistance, impact resistance, abrasion resistance, erosion resistance, and mechanical integrity (coating-substrate interface strength). drilling environment. The coatings disclosed herein can also withstand complex geometry applications without compromising substrate properties. In addition, the coatings disclosed herein also provide the low energy surface needed to provide resistance to downhole device balling.

Exemplary coated sleeved device embodiments:

Discussions of the drilling process have focused on the friction and wear benefits of coated sleeved devices, primarily applied to cylinders in sliding contact, and low energy surfaces have also been identified for reducing adhesion of formation cuttings to the bottom hole Benefits of the device. These same technical descriptions apply to the case of other cylinders in sliding contact due to relative motion, which is suitable for the use of coated sleeved devices with correspondingly modified cases.

Reduction of friction and wear is the main motivation for applying coatings to bodies that are in sliding contact due to relative motion. For stationary installations, the motivations and benefits of the coating may be slightly different. Although friction and wear may be important secondary factors (such as in the initial installation of the device), the main benefit of coated sleeved devices may be their resistance to erosion, corrosion and deposition, more similar to The problem of reducing the adhesion of BHA to shale formations, and these factors then become the main basis for their selection and use.

In an exemplary embodiment, a coated sleeved oil and gas well production device includes an oil and gas well production device comprising: 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 selected from non- Crystalline alloys, heat-treated electroless or electroplated nickel-phosphorous composites (where the phosphorus content is greater than 12 wt%), graphite, MoS ₂ , WS ₂ , fullerene-based composites, boride-based cermets , quasicrystalline materials, diamond-based materials, diamond-like carbon (DLC), boron nitride, and combinations thereof.

In another exemplary embodiment, a coated oil and gas well production device includes an oil and gas well production device comprising: one or more bodies, wherein the one or more bodies do not include a drill bit; and one or more sleeves adjacent the outer or inner surface of the one or more bodies; and on at least a portion of the inner sleeve surface, the outer sleeve surface, or a combination thereof of the one or more sleeves coating, wherein the coating is selected from amorphous alloys, heat-treated electroless or electroplated nickel-phosphorous composites (wherein the phosphorus content is greater than 12wt%), graphite, MoS ₂ , WS ₂ ene composites, boride-based cermets, quasi-crystalline materials, diamond-based materials, diamond-like carbon (DLC), boron nitride, and combinations of the above.

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 can be calculated as follows: friction force = normal force × friction coefficient. In another form, the coated oil and gas well production device may have a dynamic coefficient of friction of the coating that is not less than 50% or 60% or 70% or 80% or 90% of the coating's static coefficient of friction. In yet another form, the coated oil and gas well production device may have a dynamic coefficient of friction of the coating that is greater than or equal to the static coefficient of friction of the coating.

The coated sleeved oil and gas well production device can be made of iron-based steel, Al-based alloy, Ni-based alloy and Ti-based alloy. Type 4142 steel is a non-limiting exemplary iron-based steel for sleeved oil and gas well production devices. The surface of the iron-based steel substrate may optionally undergo a prior surface treatment prior to application of the coating. Advance surface treatment may provide one or more of the following benefits: extended durability of the coating, enhanced wear resistance, reduced coefficient of friction, enhanced fatigue resistance, and extended corrosion resistance. Non-limiting exemplary advance surface treatments include: ion implantation, nitriding, carbonizing, shot peening, laser and electron beam glazing, laser shot peening processes, and combinations thereof. This surface treatment can inhibit crack growth from fatigue, impact and abrasion damage by introducing additional substances to harden the substrate surface and/or introduce deep compressive residual stresses.

The coating of the coated sleeved oil and gas well production device disclosed herein may be selected from amorphous alloys, heat-treated electroless or electroplated nickel-phosphorus based composites, graphite, MoS ₂ , WS ₂ , based Composite materials of fullerenes, boride-based cermets, quasi-crystalline materials, diamond-based materials, diamond-like carbon (DLC), boron nitride, and combinations of the above. The diamond based material may be chemical vapor deposited (CVD) diamond or polycrystalline diamond block (PDC). In an advantageous embodiment, the coated oil and gas well production device is coated with a diamond-like carbon (DLC) coating, and more specifically the DLC coating may be selected from tetrahedral amorphous carbon (ta-C), Tetrahedral amorphous hydrogenated carbon (ta-C:H), diamond-like hydrogenated carbon (DLCH), polymer-like hydrogenated carbon (PLCH), graphite-like hydrogenated carbon (GLCH), silicon-containing diamond-like carbon (Si-DLC) , metal-containing diamond-like carbon (Me-DLC), oxygen-containing diamond-like carbon (O-DLC), nitrogen-containing diamond-like carbon (N-DLC), boron-containing diamond-like carbon (B-DLC), fluorine fluorinated diamond-like carbon (F-DLC) and combinations of the above.

Significantly reducing the coefficient of friction (COF) of the coated oil and gas well production device will result in a reduction in friction. When the device is a coated drill stem assembly, this translates into less force required to slide the cuttings along the surface. If the friction is low enough, the mobility of the chips along the surface can be increased 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 chips along the surface may inhibit the pressure caused by the differential pressure between the drilling fluid and the chip-cutter interface region that is squeezed by the drilling fluid, keeping the chips on the cutter face. Formation of chips that get stuck to varying degrees. Reducing the COF on the surfaces of oil and gas well production devices is accomplished by coating these surfaces with the coatings disclosed herein. These coatings applied to oil and gas well production equipment are able to withstand the hostile drilling environment, including resistance to erosion, corrosion, shock loads and exposure to high temperatures.

In addition to low COF, the coatings of the present disclosure also have sufficiently high hardness to provide durability against abrasion during oil and gas well production operations. More specifically, the Vickers hardness or equivalent Vickers hardness of the coating 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 the coated oil and gas well production device to be used when used as a drill pipe assembly for drilling shale with water-based drilling fluids and with screw stabilizers. Helical stabilizers are less prone to causing BHA vibrations than straight blade stabilizers. Figure 15 depicts the relationship between coating COF and coating hardness for certain coatings disclosed herein relative to prior art drill string and BHA steel. When used as a face coating on a drill stem assembly, the combination of low COF and high hardness of the coatings disclosed herein provides a tough, low COF durable material for downhole drilling applications.

A coated sleeved oil and gas well production device with a coating disclosed herein also provides a surface energy of 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 underground rotary drilling operations, this helps mitigate sticking or balling caused by rock cuttings. The contact angle can also be used to quantify the surface energy of the coatings on the coated sleeved oil and gas well production devices disclosed herein. The coatings disclosed herein have water contact angles greater than 50, 60, 70, 80, or 90 degrees.

Further details regarding the coatings disclosed herein for use in the coated sleeved oil and gas well production devices are as follows:

Amorphous alloy:

Amorphous alloys as coatings for the coated oil and gas well production devices disclosed herein provide high elastic limit/flow strength at relatively high hardness. These properties allow these materials to retain elasticity for higher strains/stresses when subjected to stress or strain compared to crystalline materials such as steel used in drill stem assemblies. The stress-strain relationship between amorphous alloys and conventional crystalline alloys/steels for coatings of drill stem components is depicted in Figure 16, and shows conventional crystalline alloys/steels versus amorphous alloys Can easily transform into plastic deformation at lower strain/stress than plastic. Premature plastic deformation at the contact surface causes the crystalline metal to generate surface asperities and a resultant high asperity contact force and COF. The high elastic limit of amorphous metal alloys or amorphous materials generally reduces the formation of asperities, which also leads to a significant increase in wear resistance. Amorphous alloys as coatings for sleeved oil and gas well production devices will result in reduced asperities formed during production operations and thereby reduce the COF of the device.

Amorphous alloys as coatings for sleeved oil and gas well production devices can be deposited using a variety of coating techniques including, but not limited to, thermal spray, cold spray, overlay welding, laser beam surface glazing, ion implantation and vapor deposition. Using a scanned laser or electron beam, the surface can be glazed and rapidly cooled to form an amorphous surface layer. In enamelling, it may be advantageous to modify the surface composition to ensure good glass formability and increase hardness and wear resistance. This can be done by blending into a molten pool on the surface as it scans over the heat source. Hardcoats may also be applied by thermal spraying, including plasma spraying, in air or vacuum. Thinner fully amorphous coatings as coatings for oil and gas well production devices can be obtained by thin film deposition techniques including but not limited to sputtering, chemical vapor deposition (CVD) and arc deposition. Certain amorphous alloy compositions disclosed herein, such as near equiatomic stoichiometry (eg, Ni—Ti), can be decrystallized by replastic deformation such as shot peening or impact loading. The amorphous alloys disclosed herein as coatings for oil and gas well production devices yield a good balance of wear and friction properties and require sufficient glass forming capability for the production technology to be employed.

Ni-P based composite coating:

Electroless and electroplated nickel-phosphorus (Ni-P) based composites disclosed herein for use in sleeved oil and gas well production devices can be obtained by co-depositing inert particles from an electrolytic or electroless bath onto a metal substrate And formed. The Ni-P composite coating provides excellent adhesion to most metal and alloy substrates. The final properties of these coatings depend on the phosphorus content of the Ni-P matrix, which determines the structure of the coating, and on the properties of the embedded particles, such as type, shape and size. Ni-P coatings with low phosphorus content are crystalline Ni with supersaturated P. By increasing the P content, the crystal lattice of nickel becomes tighter and the crystal size decreases. At phosphorus contents greater than 12wt% or 13wt% or 14wt% or 15wt% the coating exhibits mainly an amorphous structure. Annealing of the amorphous Ni-P coating can cause the transformation of the amorphous structure into a favorable crystalline state. This crystallization increases hardness, but deteriorates corrosion resistance. The more phosphorous the alloy is, the slower the crystallization process will be. This expands the amorphous range of the coating. Ni-P composite coating can add other metal elements, including but not limited to tungsten (W) and molybdenum (Mo), to further enhance the performance of the coating. The nickel-phosphorus (Ni—P) based composite coatings disclosed herein may include micron-sized and sub-micron sized particles. Non-limiting exemplary particles include: diamond, nanotubes, carbides, nitrides, borides, oxides, and combinations thereof. Other non-limiting exemplary particles include plastics (eg, fluoropolymers) and hard metals.

Layered materials and novel composite coatings:

Layered materials such as graphite, MoS ₂ and WS ₂ (2H polymorph platelets) can be used as coatings for casing oil and gas well production devices. In addition, fullerene-based composite coating layers including fullerene-like nanoparticles may also be used as coatings for oil and gas well production devices. Fullerene-like nanoparticles possess favorable tribological properties compared to typical metals, while mitigating the disadvantages of conventional layered materials (eg, graphite, MoS ₂ ). Near-spherical fullerenes can also function as nanoscale ball bearings. The main beneficial benefits of hollow fullerene-like nanoparticles contribute to the following three actions: (a) rolling friction; (b) fullerene nanoparticles serve as spacers, which eliminate the unevenness of two matching metal surfaces between the metal-to-metal contact, and (c) the transfer of the three bulk materials. Sliding/rolling of fullerene-like nanoparticles in the interface between friction surfaces may be the dominant friction mechanism at low loads when the shape of the nanoparticles is preserved. The beneficial effect of fullerene-like nanoparticles increases with load. The outer layer of fullerene-like nanoparticles was found to be exfoliated under high contact load (~1 GPa). The transfer of delaminated fullerene-like nanoparticles appears to be the dominant friction mechanism under harsh contact conditions. The mechanical and tribological properties of fullerene-like nanoparticles can be exploited by incorporating these particles in the binder phase of the coating layer. Furthermore, composite coatings incorporating fullerene-like nanoparticles in a metallic binder phase (e.g., Ni-P electroless plating) can provide self-lubricating and excellent Anti-adhesive properties of the film.

Advanced boride-based cermet and metal matrix composites:

Advanced boride-based cermet and metal matrix composites as coatings for casing oil and gas well production devices can form in bulk materials due to high temperature exposure from heat treatment or initial heating during abrasive maintenance superior. For example, in boride-based cermets (eg, TiB ₂ -metal), the surface layer is usually rich in boron oxides (eg, B ₂ O ₃ ), which enhance lubricity, resulting in a low coefficient of friction.

Quasi-crystalline materials:

Quasi-crystalline materials can be used as coatings for production devices in casing oil and gas wells. Quasicrystalline materials have a periodic atomic structure, but do not conform to the 3-D symmetry usually found in ordinary crystalline materials. Due to their crystallographic structure, mostly icosahedral or decahedral, quasicrystalline materials with tailored chemistry present a unique combination of properties, including low-energy surfaces, which are used as coatings for oil and gas well production devices. Layer material is attractive. Quasicrystalline materials provide non-stick surface properties due to their low surface energy (~30 mJ/m ² ) on stainless steel substrates with icosahedral Al-Cu-Fe chemistry. Quasi-crystalline materials as coatings for oil and gas well production devices offer low coefficient of friction (~0.05 in scratch test with diamond indenter in dry air) and relatively high microhardness (400~600HV ) combination for wear resistance. Quasi-crystalline materials as coating layers for oil and gas well production devices can also provide a low corrosion surface and the coated layer has a smooth and planar surface with low surface energy for enhanced performance. Quasi-crystalline materials can be deposited on metal substrates by a wide range of coating techniques including, but not limited to, thermal spraying, vapor deposition, laser cladding, welding build-up, and arc deposition.

Superhard materials (diamond, diamond-like carbon, cubic boron nitride):

Superhard materials such as diamond, diamond-like carbon (DLC) and cubic boron nitride (CBN) can be used as coatings for casing oil and gas well production devices. Diamond is the hardest material known to man and produces an ultra-low coefficient of friction when deposited on the sleeve element by chemical vapor deposition (herein abbreviated CVD) under certain conditions. In one form, CVD deposited carbon can be deposited directly on the surface of the sleeve. In another form, a base coat of 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 not only provides a reduced tendency for cuttings to stick at the surface, but also enables Gulf of Mexico) using a helical stabilizer. Coating the flow surface of the helical stabilizer with CVD diamond allows chips to flow through the stabilizer, up the hole and into the drill string annulus without sticking to the stabilizer.

In one advantageous embodiment, diamond-like carbon (DLC) may be used as a coating for casing oil and gas well production devices. DLC refers to an amorphous carbon material that exhibits some unique properties similar to natural diamond. Diamond-like carbon (DLC) suitable for oil and gas well production devices with sleeves can be selected from ta-C, ta-C:H, DLCH, PLCH, GLCH, Si-DLC, Me-DLC, F-DLC and combinations of the above . The DLC coating includes a large number ^of sp doped carbon atoms. These sp bonds occur not only in crystals ^— in other words, solids with long-range order—but also in amorphous solids with random arrangements of atoms. In this case, there will be bonding between only a few individual atoms, ie short-range order, rather than long-range order extending over a large number of atoms. The bond type has a considerable influence on the material properties of amorphous carbon films. The DLC film may be softer if it is predominantly sp ² type, and harder if it is predominantly sp ³ type.

DLC coatings can be made as amorphous, flexible and still purely sp ³ bonded "diamonds". The hardest is a mixture known as tetrahedral amorphous carbon or ta-C (see Figure 17). This ta-C includes a high volume fraction (~80%) of sp3 ^- bonded carbon atoms. Optional fillers for DLC coatings include, but are not limited to, hydrogen, graphitic sp ² carbon, and metals, and can be used in other forms to achieve the desired combination of properties depending on the particular application. Various forms of DLC coatings can be applied to various substrates that are compatible with vacuum environments and are also conductive. DLC coating quality also depends on the fractional content of alloying elements such as hydrogen. Certain DLC coating methods require hydrogen or methane as precursor gases, and thus a significant percentage of hydrogen may remain in the finished DLC material. In order to further improve their tribological and mechanical properties, other alloying and/or doping elements are usually added to modify DLC films. For example, the addition of fluorine (F) and silicon (Si) to DLC reduces surface energy and wettability. Reducing the surface energy in fluorine-containing DLC (F-DLC) facilitates the presence of -CF2 and -CF3 groups in the film. However, higher F content can lead to lower hardness. The addition of Si can reduce the surface energy by reducing the dispersion component of the surface energy. Si addition can also increase the hardness of DLC films by promoting sp ³ hybridization in DLC films. The addition of metallic elements (e.g. W, Ta, Cr, Ti, Mo) to the film and the use of such metallic interlayers can reduce the compressive residual stress, resulting in better mechanical integrity of the film under compressive loading.

The diamond-like phase or sp3 ^- bonded carbon of DLC is the thermodynamically metastable phase, while sp2 ^- bonded graphite is the thermodynamically stable phase. Therefore, the formation of DLC coating films requires disequilibrium treatment to obtain metastable sp3 ^- bonded carbon. Equilibrium processes such as the evaporation of graphitic carbon, where the average energy of the evaporated species is low (approximately kT, where k is Boltzmann's constant and T is the temperature on the absolute scale), lead to the formation of 100% sp ² bonded carbon. The methods disclosed herein for the production of DLC coatings require the carbon to have sp ³ bond lengths that are significantly smaller than sp ² bond lengths. Thus, pressure, shock, catalysis, or some combination of these applied at the atomic scale can force sp ² bonded carbon atoms to become more densely sp ³ bonded. This can be done vigorously enough that the atoms cannot simply snap back apart to the dissociated properties of the ^sp2 bond. Typical techniques combine this compression with pushing new sp3 ^- bonded carbon clusters deeper into the coating so that there is no room for separation needed for expansion back to sp2 ^- bonding; New carbon entrapment from the next shock cycle.

The DLC coatings disclosed herein can be deposited by physical vapor deposition, chemical vapor deposition, or plasma assisted chemical vapor deposition coating techniques. Physical vapor deposition coating methods include RF-DC plasma reactive magnetron sputtering, ion beam assisted deposition, cathodic arc deposition and pulsed laser deposition (PLD). Chemical vapor deposition coating methods include ion beam assisted CVD deposition, plasma enhanced deposition, use of glow discharge from hydrocarbon gases, use of radio frequency (rf) glow discharge from hydrocarbon gases, plasma immersion ion treatment, and microwave discharge. Plasma-enhanced chemical vapor deposition (PECVD) is an advantageous method for large-area deposition of DLC at high deposition rates. Plasma-based CVD coating processes are non-line-of-sight techniques, ie, the plasma conforms to the part to be coated and the entire exposed surface of the part is coated with a uniform thickness. The surface finish of the part is preserved after the DLC coating is applied. One advantage of PECVD is that the temperature of the base part does not rise above about 150°C during the coating operation. Fluorine-containing DLC (F-DLC) and silicon-containing DLC (Si-DLC) films enable the use of acetylene mixed with fluorine- and silicon-containing precursor gases, such as tetrafluoroethane and hexamethyldisiloxane, respectively The (C ₂ H ₂ ) process gas is synthesized using plasma deposition techniques.

The DLC coatings disclosed herein can exhibit a coefficient of friction within the previously described range. Ultralow COF can be based on the formation of thin graphite films in the actual contact area. Since sp ₃ bonding is a thermodynamically unstable phase of carbon at high temperatures from 600 to 1500°C, it can transform into graphite that can act as a solid lubricant, depending on the environmental conditions. These high temperatures can appear as very brief transient temperatures (called initial temperatures) during the collision or contact of the bumps. An alternative theory for the ultra-low COF of DLC coatings is the presence of hydrocarbon-based slip films. The tetrahedral structure ^of Sp bonded carbon can lead to a situation at the surface where there may be a vacant electron from the surface to which no carbon atom can attach (see Figure 18), this is called " Suspension key" track. If a hydrogen atom with its own electron is placed on such a carbon atom, it may bond to a dangling orbital, forming a two-electron covalent bond. When two such smooth surfaces, with an outer layer of individual hydrogen atoms, slide over each other, shearing occurs between the hydrogen atoms. There is no chemical bonding between the surfaces, only weak van der Waals forces exist, and the surface presents the properties of heavy hydrocarbon wax. As shown in Figure 18, the carbon atoms at the surface can form three robusts, leaving one electron in a dangling bond orbital drawn from the surface. Hydrogen atoms attach to this surface, which becomes hydrophobic and exhibits low friction.

The DLC coatings disclosed herein for casing oil and gas well production devices 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 applications experiencing extreme contact pressures of both rolling and sliding contacts.

In addition to low friction and wear/corrosion resistance, the DLC coatings disclosed herein for casing oil and gas well production devices also exhibit durability and bond strength to the exterior surfaces of the body components used for deposition. DLC coatings can have high levels of inherent residual stress (~1 GPa), which affects the tribological properties of DLC coatings and the strength of adhesion to the substrate used for deposition (e.g. steel). Typically, DLC coatings deposited directly on steel surfaces suffer from poor adhesion strength. This lack of adhesion strength limits the thickness and incompatibility between the DLC coating and the steel interface, which can lead to delamination at low loads. To overcome this problem, the DLC coatings disclosed herein may also include various metals (such as but not limited to Cr, W, Ti) and ceramic compounds (such as but not limited to Not limited to the intermediate layer of CrN, SiC). These ceramic and metal interlayers relieve the compressive residual stresses of the DLC coatings disclosed herein to increase adhesion and load carrying capacity. Alternative approaches to improve the wear/friction and mechanical durability of the DLC coatings disclosed herein are the addition of multiple layers with intermediate buffer layers to relieve residual stress buildup and/or dual hybrid coating treatments. In one form, the outer surface of the oil and gas well production device for treatment may be nitrided or carbonized, a precursor treatment, prior to the deposition of the DLC coating in order to harden and prevent the plasticity of the base layer resulting in enhanced coating durability out of shape.

Multilayer and hybrid coatings:

Multi-layer coatings on sleeved oil and gas well production devices are disclosed herein and can be used to maximize the thickness of the coating to enhance its 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. The thickness of each coating layer can be in the range from 0.5 to 5000 microns, wherein the lower limit is 0.5, 0.7, 1.0, 3.0, 5.0, 7.0, 10.0, 15.0 or 20.0 microns and the upper limit is 25, 50, 75, 100 , 200, 500, 1000, 3000 or 5000 microns. The total thickness of the multilayer coating can range from 0.5 to 30,000 microns. The lower limit for the overall multilayer coating thickness can be 0.5, 0.7, 1.0, 3.0, 5.0, 7.0, 10.0, 15.0 or 20.0 microns thick. The upper limit for the overall multilayer coating thickness, excluding hardbanding, may be 25, 50, 75, 100, 200, 500, 1000, 3000, 5000, 10000, 15000, 20000 or 30000 microns thick.

In another embodiment of the coated sleeved oil and gas well production device disclosed herein, the body assembly of the oil and gas well production device may include a hardbanding on at least a portion of the exposed outer surface to provide enhanced resistance. abrasiveness and durability. Thus, one or more coating layers are deposited on top of the hardbanding, forming a hybrid coating structure. The thickness of the hardbanding can vary from being equal to several times the thickness of the outer coating layer. Non-limiting exemplary hardbanding materials include cermet-based materials, metal-matrix composites, nanocrystalline metal alloys, amorphous alloys, and hard metal alloys. Other non-limiting exemplary types of hardbanding include carbides, nitrides, borides, and oxides of the elements tungsten, titanium, niobium, molybdenum, iron, chromium, and silicon dispersed within a metal alloy matrix. This hardbanding can be deposited by welding overlay, thermal spraying or laser/electron beam cladding.

Coatings for use in the coated sleeved oil and gas well production devices disclosed herein may also include one or more buffer layers (also referred to herein as bonding layers). In multilayer coating constructions, the one or more buffer layers may be disposed between the outer surface of the body component and a single layer or two or more layers. The one or more buffer layers may be selected 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 selected from carbides, nitrides, carbon-nitrides, oxides of the following elements: silicon, titanium, chromium, tungsten, tantalum, niobium, vanadium, zirconium and/or hafnium. The one or more buffer layers are typically placed between the hardbanding (when used) and the one or more coating layers or between coating layers. The thickness of the buffer layer can be a fraction of the thickness of the phase coating layer or close to the thickness of the coating layer.

In yet another embodiment of the coated sleeved oil and gas well production device disclosed herein, the body assembly may further include a coating or hardening disposed on the outer surface of the body assembly and on at least a portion of the exposed outer surface. One or more spacers between layers to provide enhanced toughness, to minimize any dilution from the base steel incorporated in the outer coating or hardening, and to minimize residual stress absorption. Non-limiting exemplary barrier layers include stainless steel or nickel-based alloys. The one or more isolation layers are typically positioned near or on top of a body assembly of the oil and gas well production device for coating.

In one advantageous embodiment of the coated sleeved oil and gas well production device disclosed herein, a multilayer carbon-based amorphous coating, such as a diamond-like carbon (DLC) coating, may be applied to the device. Diamond-like carbon (DLC) coatings suitable for oil and gas well production devices can be selected from ta-C, ta-C:H, DLCH, PLCH, GLCH, Si-DLC, Me-DLC, N-DLC, O-DLC, B-DLC, F-DLC and combinations of the above. A particularly advantageous DLC coating for this application is DLCH or ta-C:H. The structure of a multi-layer DLC coating may include individual DLC layers with an adhesion or buffer layer in between. Exemplary adhesion or buffer layers for use with DLC coatings include, but are not limited to, silicon, titanium, chromium, tungsten, tantalum, niobium, vanadium, zirconium, and/or hafnium, or alloys thereof. Exemplary bond or buffer layers for use with DLC coatings include, but are not limited to, carbides, nitrides, carbonitrides, oxides of the following elements: silicon, titanium, chromium, tungsten, tantalum, niobium, vanadium, zirconium and/or hafnium. These buffer or bonding layers act as toughening and residual stress relieving layers and allow the overall DLC coating thickness for multi-layer embodiments to be increased while maintaining coating integrity for durability.

In yet another advantageous form of the coated sleeved oil and gas well production device disclosed herein, in order to improve the durability, mechanical integrity and downhole performance of the relatively thin DLC coating layer, a hybrid coating method can be utilized , wherein one or more DLC coating layers may be deposited on top of prior art hardbanding. This embodiment provides enhanced DLC-hardbanding interface strength and also provides protection of the downhole device against premature wear if the DLC wears or delaminates. In another form of this embodiment, an advanced surface treatment may be applied to the steel substrate prior to application of the DLC layer to prolong durability and improve the wear, friction, fatigue and corrosion performance of the DLC coating. The advance surface treatment may be selected from ion implantation, nitriding, carbonizing, shot peening, laser and electron beam glazing, laser shot peening and combinations thereof. This surface treatment can lead to inhibition of crack growth caused by impact and abrasion damage by introducing additional substances to harden the substrate surface and/or introduce deep compressive residual stresses. In yet another form of this embodiment, one or more barrier layers as previously described may be placed between the substrate and the hardbanding, with one or more DLC coating layers placed on top of the hardbanding .

Figure 26 is an exemplary embodiment of a coating on a casing oil and gas well production device utilizing a multi-layer hybrid coating layer, wherein the DLC coating layer is deposited on top of hardbanding on a steel substrate. In another form of this embodiment, the hardband may be post-treated (e.g., etched) to expose alloy carbide particles to improve adhesion of the DLC coating to the hardband as also shown in FIG. 26 . This hybrid coating can be applied to downhole devices such as tool joints and stabilizers to improve the durability and mechanical integrity of DLC coatings deposited on these devices and provide A "second line of defense" against the aggressive wear and erosion conditions of the downhole environment in underground rotary drilling operations. In another form of this embodiment, one or more buffer layers and/or one or more barrier layers as described above may be included in a hybrid coating structure to further enhance oil and gas well drilling, well completion and The characteristics and performance of production operations.

Applying these coating technologies to casings in proximity to oil and gas well production facilities offers potential benefits, including but not limited to drilling, completions, production, workover, and production operations. Efficient and reliable drilling, completions, oil recovery, workover and production operations can be enhanced by applying such coatings to sleeved devices to mitigate friction, wear, erosion, corrosion and deposits as discussed in detail above.

Exemplary methods of using coated sleeved device embodiments:

In an exemplary embodiment, an advantageous method of using a sleeved oil and gas well production device includes providing a coated oil and gas well production device comprising one or more a cylindrical body with one or more sleeves adjacent the outer diameter or inner diameter of the one or more cylindrical bodies and an inner sleeve surface, an outer sleeve surface, or a combination of the one or more sleeves The coating on at least a part of the coating, wherein the coating is selected from amorphous alloys, heat-treated electroless or electroplated nickel-phosphorus composites (wherein the phosphorus content is greater than 12wt%), graphite, MoS ₂ , WS ₂ , Fullerene-based composites, boride-based cermets, quasi-crystalline materials, diamond-based materials, diamond-like carbon (DLC), boron nitride, and combinations thereof; and in well construction, completion, or production operations Utilizes coated casing oil and gas well production devices.

In another exemplary embodiment, an advantageous method of using a sleeved oil and gas well production device includes providing a coated oil and gas well production device comprising one or more A plurality of bodies, wherein the one or more bodies do not include a drill bit, having one or more sleeves near an outer surface or an inner surface of the one or more bodies; and inside the one or more sleeves A coating on at least a portion of a sleeve surface, an outer sleeve surface, or a combination thereof, wherein the coating is selected from amorphous alloys, heat-treated electroless or electroplated nickel-phosphorous based composites (wherein the phosphorus content is greater than 12wt%), graphite, MoS ₂ , WS ₂ , fullerene-based composites, boride-based cermets, quasi-crystalline materials, diamond-based materials, diamond-like carbon (DLC), boron nitride and the above combination; and utilizing the coated sleeved oil and gas well production device in well construction, well completion or production operations.

experiment method:

The coefficient of friction was measured using a ball-on-disk tester according to ASTM G99 test method. This test method requires two samples—a flat disk sample and a ball sample with a spherical end. Ball samples held rigidly by holders were positioned perpendicular to the flat disc. The flat disk sample was slid against the ball sample by rotating the 2.7 inch diameter flat disk in a circular path. A normal load is applied vertically downward through the ball so that the ball compresses against the disc. Specific normal loads can be applied by means of attached weights, hydraulic or pneumatic loading mechanisms. During the test, friction is measured using a tension-compression load cell or similar force sensing device attached to the ball mount. The coefficient of friction can be calculated by dividing the measured friction force by the normal load. Tests were done at various test conditions sliding speeds and at room temperature and 150°F. Quartz or low carbon steel balls with a diameter of 4mm~5mm are used as the mating surface material.

Speed enhancement or reduction was evaluated by measuring the coefficient of friction at various sliding speeds using a ball-on-disk friction tester by means of the above-mentioned ASTM G99 test method.

Hardness was measured according to ASTM C1327 Vickers hardness test method. The Vickers hardness test method involves indenting the test material using a diamond indenter in the form of a right pyramid with a square base and an angle of 136 degrees between opposing surfaces subjected to a load of 1 to 100 kgf. Usually the full load is applied for 10 to 15 seconds. Two diagonal corners of the indentation left in the surface of the material after removal of the load are measured using a microscope and their average value is calculated. Calculate the area of the sloped surface of the indentation. The Vickers hardness is a quotient obtained by dividing the kgf load by the square millimeter area of the indentation. The advantage of the Vickers hardness test is that it allows extremely accurate readings and uses only one indenter for all types of metals and surface treatments. The hardness of thin coating layers (e.g., less than 100 μm) has been evaluated by nanoindentation, where the normal load (P) is passed through an indenter with well-known pyramidal geometry (e.g., Berkovich tip, which has a three-sided pyramidal geometry) Apply a normal load (P) to the coated surface. Small loads and tip sizes are used in nanoindentation to eliminate or reduce the contribution from the substrate, so the indentation area may be only a few square micrometers or even nanometers. During the nanoindentation process, the penetration depth is recorded and the area of the indentation is then determined using the known geometry of the indentation tip. Hardness can be obtained by dividing the load (kgf) by the area of the indentation (mm2).

Wear properties were measured by ball-on-disk geometry according to ASTM G99 test method. The amount of ball and disk wear or wear volume loss is determined by measuring the dimensions of the two samples before and after the test. Depth or shape changes of the wear track of the disk are determined by laser surface profilometer and atomic force microscope. The amount of ball wear, or wear volume loss, is determined by measuring the dimensions of the sample before and after the test. The wear volume of the ball is calculated from the known geometry and dimensions of the ball.

Water contact angles were measured according to ASTM D5725 test method. A method known as the "sessional drop method" uses an optical subsystem-based goniometer to measure the liquid contact angle to capture the profile of a pure liquid on a solid substrate. A liquid droplet (eg, water) is placed (or allowed to fall from a distance) onto a solid surface. When the liquid settles (has become immobilized), the droplet maintains its surface tension and becomes oval against the solid surface. The angle formed between the liquid/solid interface and the liquid/vapor interface is the contact angle. The contact angle formed by the ellipse of the droplet touching the above-mentioned surface determines the degree of affinity between the two substances. That is, flat droplets indicate high affinity, in which case the liquid is considered to "wet" the substrate. Droplets that are more rounded (by height) above the surface indicate lower affinity because the angle at which the liquid attaches to the solid surface is sharper. In this case, the liquid is considered a "non-wetting" substrate. The sessile droplet system employs a high-resolution camera and software to capture and analyze contact angles.

Example

Exemplary embodiment 1:

DLC coating was applied on 4142 steel substrate by vapor deposition technique. The DLC coating has a thickness ranging from 1.5 to 25 microns. Hardness is measured to be in the range of 1,300 to 7,500 Vickers hardness numbers. Laboratory tests based on ball-on-disk geometry were performed to demonstrate the friction and wear properties of the coating. Quartz balls and mild steel balls are used as mating surface materials to simulate open hole and cased hole conditions, respectively. In an ambient temperature test, uncoated 4142 steel, DLC coated and commercially available Prior art hardfacing coatings to simulate open hole conditions. An increase in friction performance (reduction in coefficient of friction) of up to 10 times that of uncoated 4142 steel and hardening can be achieved in DLC coatings as shown in Figure 19.

In another ambient temperature test, uncoated 4142 steel, a DLC coating, and a commercial prior art hardfacing coating were tested on mild steel mating materials to simulate jacketed hole conditions. Friction performance (reduction in coefficient of friction) up to three times that of uncoated 4142 steel and hardening can be achieved in the DLC coating shown in Figure 19 . DLC coating Polished quartz balls due to the higher hardness of the DLC coating than the mating surface material (ie, quartz and mild steel). However, volume loss due to wear is minimal in both quartz and mild steel balls. Plain steel and hardening on the other hand lead to significant wear in both the quartz balls and the mild steel balls, indicating that these are not very "casing friendly".

Ball-disk wear and coefficient of friction were also tested in oil-based drilling fluids at ambient temperature. Quartz balls and mild steel balls are used as mating surface materials to simulate open hole and cased hole conditions, respectively. DLC coatings exhibit significant advantages over commercial hardbanding as shown in Figure 20. The use of DLC coatings can achieve friction performance improvements (reduction in coefficient of friction) of up to 30% compared to uncoated 4142 steel and hardening. DLC coating polishes quartz balls due to its higher hardness than quartz. On the other hand, in the case of uncoated steel discs, both the mild steel and quartz balls and the steel discs showed significant wear. For comparable testing, the wear characteristics of the hardened disks were intermediate between the DLC coated disks and the uncoated steel disks.

Figure 21 depicts the wear and friction properties at elevated temperatures. Tests were performed in an oil-based drilling fluid heated to 150°F, and again quartz balls and mild steel balls were used as mating surface materials to simulate open hole and cased hole conditions, respectively. DLC coatings exhibit up to 50% improvement in friction performance (decrease in coefficient of friction) compared to uncoated 4142 steel and commercial hardbanding. Uncoated steel and hardening resulted in wear damage to the mating face material of the quartz and mild steel balls, while significantly less wear damage was observed in the mating face material rubbing against the DLC coating.

Figure 22 shows the tribological properties of the DLC coating at elevated temperatures (150°F and 200°F). In this test data, the DLC coating exhibited a low coefficient of friction at elevated temperatures up to 200°F. However, the coefficient of friction of uncoated steel and hardening increases significantly with temperature.

Exemplary embodiment 2:

In laboratory wear/friction tests, the velocity of the coefficient of friction was measured on DLC coated and uncoated 4142 steel by monitoring the shear stress required to slide over a sliding velocity range of 0.3m/sec to 1.8m/sec Dependency (speed reduction or enhancement). Quartz balls are used as mating surface material in dry sliding friction tests. The velocity attenuation performance of DLC coatings relative to uncoated steel is depicted in FIG. 23 . Uncoated 4142 steel exhibits a decreasing coefficient of friction with sliding velocity (i.e., a pronounced velocity weakening), whereas the DLC coating exhibits no velocity weakening and in fact appears to be a slight velocity enhancement of COF (i.e., COF increases with sliding Velocity increases slightly), which can be beneficial for mitigating torsional instability (a precursor to slip stick vibration).

Exemplary embodiment 3:

Multi-layer DLC coatings are produced in order to maximize the thickness of the DLC coating, thereby increasing its durability for drilling components used in drilling operations. In one form, the total thickness of the multilayer DLC coating varies from 6 μm to 25 μm. Figure 24 depicts SEM images of both single and multilayer DLC coatings for drill stem components produced via PECVD. The bonding layer used with the DLC coating is a silicon-containing buffer layer.

Exemplary embodiment 4:

The surface energy of the DLC coated substrate compared to the uncoated 4142 steel surface was measured via water contact angle. The results are depicted in Figure 25 and show that the DLC coating provides significantly lower surface energy compared to the uncoated steel surface. Lower surface energy may provide a less adherent surface to mitigate or reduce bit/stabilizer balling and prevent the formation of deposits of asphalt, paraffin, scale and/or hydrate.

Applicants have attempted to disclose all implementations and applications of the disclosed subject matter that are reasonably foreseeable. However, there may be unforeseen insubstantial modifications that are still equivalent. While the invention has been described in conjunction with specific exemplary embodiments of the invention, it will be apparent from the foregoing description that many changes, modifications and variations will be apparent to those skilled in the art without departing from the spirit and scope of the invention. will be obvious. Accordingly, the present invention is intended to embrace all such alterations, modifications and variations of the above detailed description.

All patents, test procedures, and other documents cited herein, including priority documents, are fully incorporated by reference to the extent that such disclosure is not inconsistent with the present invention and for all jurisdictions in which such incorporation was permitted.

When numerical lower limits and numerical upper limits are recited herein, ranges from any lower limit to any upper limit are contemplated.

Claims (160)

1. A coated sleeved oil and gas well production device comprising: one or more cylindrical bodies; one or more sleeves proximate the outer or inner diameter of the one or more cylindrical bodies, wherein the one or more sleeves are designed to fit on another a tubular part on a part, and a coating on at least a portion of an inner sleeve surface, an outer sleeve surface, or a combination of an inner sleeve surface and an outer surface of the one or more sleeves, Wherein, the coating is selected from fullerene-based composite materials, diamond-like carbon (DLC) and combinations thereof, Wherein the coating has a coefficient of friction less than or equal to 0.15, and the coating provides a hardness greater than 1000 VHN. 2. The coated sleeved oil and gas well production device of claim 1, wherein the one or more cylindrical bodies comprises two or more cylindrical bodies that move relative to each other. 3. The coated sleeved oil and gas well production device of claim 1, wherein the one or more cylindrical bodies comprises two or more cylindrical bodies that are stationary relative to each other. 4. The coated sleeved oil and gas well production device of claim 3, wherein the two or more cylindrical bodies comprise two or more radii. 5. The coated sleeved oil and gas well production device of claim 4, wherein the two or more cylindrical bodies comprise one substantially within one or more other cylindrical bodies or more cylindrical bodies. 6. The coated sleeved oil and gas well production device of claim 4, wherein the two or more radii have substantially the same size or substantially different sizes. 7. The coated sleeved oil and gas well production device of claim 4, wherein the two or more cylindrical bodies border each other. 8. The coated sleeved oil and gas well production device of claim 4, wherein the two or more cylindrical bodies do not border each other. 9. The coated sleeved oil and gas well production device of claim 7 or 8, wherein the two or more cylindrical bodies are coaxial or non-coaxial. 10. The coated sleeved oil and gas well production device of claim 9, wherein the bodies have substantially parallel axes. 11. The coated sleeved oil and gas well production device of claim 1, wherein the one or more cylindrical bodies are helical in the inner surface, helical in the outer surface, or the foregoing combination. 12. The coated sleeved oil and gas well production device of claim 1, wherein the one or more cylindrical bodies are solid, hollow, or a combination thereof. 13. The coated sleeved oil and gas well production device of claim 1, wherein the one or more cylindrical bodies comprise an outer cross-section, an inner cross-section, or an inner cross-section and the outer cross-section is substantially At least one cylindrical body that is substantially circular, substantially elliptical, or substantially polygonal. 14. The coated sleeved oil and gas well production device of claim 1, wherein the coating has a coefficient of friction of less than or equal to 0.10. 15. The coated sleeved oil and gas well production device of claim 1, wherein the coating provides a hardness greater than 1500 VHN. 16. The coated sleeved oil and gas well production device of claim 1, wherein the coating provides at least 3 times greater wear resistance than an uncoated device. 17. The coated sleeved oil and gas well production device of claim 1, wherein the coating has a water contact angle greater than 60 degrees. 18. The coated sleeved oil and gas well production device of claim 1, wherein the coating provides a surface energy of less than ¹ J/m2. 19. The coated sleeved oil and gas well production device of claim 18, wherein the coating provides a surface energy of less ^than 0.1 J/m2. 20. The coated sleeved oil and gas well production device of claim 1, wherein the coating comprises a single coating layer or two or more coating layers. 21. The coated sleeved oil and gas well production device of claim 20, wherein the two or more coating layers have substantially the same or different coatings. 22. The coated sleeved oil and gas well production device of claim 20, wherein the thickness of the single coating layer and the thickness of each of the two or more coating layers are between range from 0.5 microns to 5000 microns. 23. The coated sleeved oil and gas well production device of claim 20, wherein the coating further comprises one or more buffer layers. 24. The coated sleeved oil and gas well production device of claim 23, wherein said one or more buffer layers are disposed on the surface of said one or more cylindrical bodies and said single coated coating or between the two or more coating layers. 25. The coated sleeved oil and gas well production device of claim 23, wherein the one or more buffer layers are selected from the group consisting of elements, alloys, carbides, nitrides, carbon-nitrides, and Oxides: silicon, titanium, chromium, tungsten, tantalum, niobium, vanadium, zirconium or hafnium. 26. The coated sleeved oil and gas well production device of claim 1, wherein the dynamic coefficient of friction of the coating is no less than 50% of the static coefficient of friction of the coating. 27. The coated sleeved oil and gas well production device of claim 1, wherein the dynamic coefficient of friction of the coating is greater than or equal to the static coefficient of friction of the coating. 28. The coated sleeved oil and gas well production device of claim 1, wherein the one or more cylindrical bodies further comprise a hardbanding on at least a portion thereof. 29. The coated sleeved oil and gas well production device of claim 28, wherein the hardbanding comprises a cermet-based material, a metal-matrix composite, or a hard metal alloy. 30. The coated sleeved oil and gas well production device of claim 1 or 28, wherein the one or more cylindrical bodies further comprise a surface disposed on the one or more cylindrical bodies and a spacer between said coating or hardbanding on at least a portion of said cylindrical body. 31. The coated sleeved oil and gas well production device of claim 30, wherein the isolation layer comprises stainless steel or a nickel-based alloy. 32. The coated sleeved oil and gas well production device of claim 1, wherein the one or more cylindrical bodies further comprise threads. 33. The coated sleeved oil and gas well production device of claim 32, wherein at least a portion of the threads are coated. 34. The coated sleeved oil and gas well production device of claim 32 or 33, further comprising a sealing surface, wherein at least a portion of the sealing surface is coated. 35. The coated sleeved oil and gas well production device of any one of claims 1, 2, or 3, wherein the one or more cylindrical bodies are well construction devices. 36. The coated sleeved oil and gas well production device of claim 35, wherein said well construction device is selected from the group consisting of: drill pipe, casing, tubing string, wire rope/braided rope/multicore conductor/single Core conductors/well test slicklines; coiled tubing and vane rotors and stators for progressive chamber pumps, expandable tubing, expansion mandrels, centralizers, contact rings, flushing lines, shaker screens for solids control, salvage and grapples, subsea risers, surface flow lines, and combinations of the above. 37. The coated sleeved oil and gas well production device of any one of claims 1, 2, or 3, wherein the one or more cylindrical bodies are completion and production devices. 38. The coated sleeved oil and gas well production device of claim 37, wherein said completion and production device is selected from the group consisting of: a plunger lift device; a completion sliding sleeve assembly; coiled tubing; Suction rods; tubing strings; oil pumps; stuffing boxes; seals and lubricators; pistons and piston liners; vane rotors and stators for progressive cavity pumps; expandable fittings; expansion mandrels; control lines and conduits ;tools for operation in wellbore;steel wire rope/braided rope/multicore conductor/single core conductor/well test wire; centralizer; contact ring; perforated base pipe; slotted base pipe; screen base pipe for sand control ;flush lines;splitter tubes;service tools for gravel pack operations;wear joints;sand screens set in completion intervals;sand screens with redundant sand control and barrier compartments sintered screens; wire wound screens; shaker screens for solids control; overshots and grapples; subsea risers; surface flow lines; oil production process lines, and combinations of the above. 39. The coated sleeved oil and gas well production device of claim 1, wherein the one or more cylindrical bodies are pin or sleeve connections of a tubing tool joint. 40. The coated sleeved oil and gas well production device of claim 39, wherein the one or more cylindrical bodies are configured with a proximal cylindrical cross-section that is circular in cross-section. 41. The coated sleeved oil and gas well production device of claim 39, wherein the one or more cylindrical bodies are configured with a proximal cylindrical cross-section that is non-circular in cross-section. 42. The coated sleeved oil and gas well production device of claim 39, wherein the pin or sleeve connection is oriented such that the pin faces upward and the sleeve faces downward relative to the direction of gravity. 43. The coated sleeved oil and gas well production device of claim 39, wherein the pin or sleeve connection is oriented such that the pin faces downward and the sleeve faces upward relative to the direction of gravity. 44. The coated sleeved oil and gas well production device of claim 1, wherein said one or more sleeves comprise metal, metal alloy, ceramic, cermet, polymer, carbon steel, steel alloy , stainless steel, WC-based hard metal, or a combination of the above. 45. A coated sleeved oil and gas well production device comprising: an oil and gas well production device comprising one or more bodies, wherein the one or more bodies do not include a drill bit, one or more sleeves proximate to an outer or inner surface of the one or more bodies, wherein the one or more sleeves are designed to fit over another Tubular parts on parts, and a coating on at least a portion of an inner sleeve surface, an outer sleeve surface, or a combination of an inner sleeve surface and an outer surface of the one or more sleeves, wherein the coating is selected from the group consisting of fullerene-based composites, diamond-like carbon (DLC), and combinations thereof, Wherein the coating has a coefficient of friction less than or equal to 0.15, and the coating provides a hardness greater than 1000 VHN. 46. The coated sleeved oil and gas well production device of claim 45, wherein the one or more bodies comprises two or more bodies that move relative to each other. 47. The coated sleeved oil and gas well production device of claim 45, wherein the one or more bodies comprises two or more bodies that are stationary relative to each other. 48. The coated sleeved oil and gas well production device of claim 45, wherein the one or more bodies comprise spherical and complex geometric shapes. 49. The coated sleeved oil and gas well production device of claim 48, wherein the complex geometric shape has at least a portion that is a non-cylindrical shape. 50. The coated sleeved oil and gas well production device of claim 46 or 47, wherein the two or more bodies comprise one or more bodies substantially within one or more other bodies. multiple ontologies. 51. The coated sleeved oil and gas well production device of claim 46 or 47, wherein the two or more bodies border each other. 52. The coated sleeved oil and gas well production device of claim 46 or 47, wherein the two or more bodies do not border each other. 53. The coated sleeved oil and gas well production device of claim 46 or 47, wherein the two or more bodies are coaxial or non-coaxial. 54. The coated sleeved oil and gas well production device of claim 45, wherein the one or more bodies are solid, hollow, or a combination thereof. 55. The coated sleeved oil and gas well production device of claim 45, wherein the one or more bodies comprise an outer cross-section, an inner cross-section, or an inner cross-section and the outer cross-section are substantially circular At least one body that is rectangular, substantially elliptical, or substantially polygonal. 56. The coated sleeved oil and gas well production device of claim 45, wherein the coating has a coefficient of friction less than or equal to 0.10. 57. The coated sleeved oil and gas well production device of claim 45, wherein the coating provides a hardness greater than 1500 VHN. 58. The coated sleeved oil and gas well production device of claim 45, wherein the coating provides at least 3 times greater wear resistance than an uncoated device. 59. The coated sleeved oil and gas well production device of claim 45, wherein the coating has a water contact angle greater than 60 degrees. 60. The coated sleeved oil and gas well production device of claim 45, wherein the coating provides a surface energy of less than ¹ J/m2. 61. The coated sleeved oil and gas well production device of claim 60, wherein the coating provides a surface energy of less ^than 0.1 J/m2. 62. The coated sleeved oil and gas well production device of claim 45, wherein the coating comprises a single coating layer or two or more coating layers. 63. The coated sleeved oil and gas well production device of claim 62, wherein the two or more coating layers have substantially the same or different coatings. 64. The coated sleeved oil and gas well production device of claim 62, wherein the thickness of the single coating layer and the thickness of each of the two or more coating layers are between range from 0.5 microns to 5000 microns. 65. The coated sleeved oil and gas well production device of claim 62, wherein the coating further comprises one or more buffer layers. 66. The coated sleeved oil and gas well production device of claim 65, wherein said one or more buffer layers are disposed on the surface of said one or more bodies and said single coating layer Or between the two or more coating layers. 67. The coated sleeved oil and gas well production device of claim 65, wherein the one or more buffer layers are selected from the group consisting of elements, alloys, carbides, nitrides, carbon-nitrides, and Oxides: silicon, titanium, chromium, tungsten, tantalum, niobium, vanadium, zirconium or hafnium. 68. The coated sleeved oil and gas well production device of claim 45, wherein the dynamic coefficient of friction of the coating is no less than 50% of the static coefficient of friction of the coating. 69. The coated sleeved oil and gas well production device of claim 45, wherein the dynamic coefficient of friction of the coating is greater than or equal to the static coefficient of friction of the coating. 70. The coated sleeved oil and gas well production device of claim 45, wherein the one or more bodies further comprise hardbanding on at least a portion thereof. 71. The coated sleeved oil and gas well production device of claim 70, wherein the hardbanding comprises a cermet-based material, a metal-matrix composite, or a hard metal alloy. 72. The coated sleeved oil and gas well production device of claim 45 or 70, wherein said one or more bodies further comprise surfaces disposed on said one or more bodies and on said one or more bodies A barrier between said coatings or hardbanding on at least a portion of the body. 73. The coated sleeved oil and gas well production device of claim 72, wherein the isolation layer comprises stainless steel or a nickel-based alloy. 74. The coated sleeved oil and gas well production device of claim 45, wherein the one or more bodies further comprise threads. 75. The coated sleeved oil and gas well production device of claim 74, wherein at least a portion of the threads are coated. 76. The coated sleeved oil and gas well production device of claim 74 or 75, further comprising a sealing surface, wherein at least a portion of the sealing surface is coated. 77. The coated sleeved oil and gas well production device of any one of claims 45, 46, or 47, wherein the one or more bodies are well construction devices. 78. The coated sleeved oil and gas well production device of claim 77, wherein said well construction device is selected from the group consisting of: chokes, valves, valve seats, chokes, ball valves, annular isolation valves, subsurface safety valves , centrifuges, elbows, tees, couplings, blowout preventers, wear bushings, dynamic metal-to-metal seals in reciprocating and/or rotating seal assemblies, springs in safety valves, damping joints and shock absorbers Hammers, logging tool arms, rig skidding devices, pawls, and combinations of the above. 79. The coated sleeved oil and gas well production device of any one of claims 45, 46, or 47, wherein the one or more bodies are completion and production devices. 80. The coated sleeved oil and gas well production device of claim 79, wherein said completion and production device is selected from the group consisting of: chokes, valves, valve seats, chokes, ball valves, inflow control devices, intelligent Well valves, annular isolation valves, subsurface safety valves, centrifuges, gas lift and chemical injection valves, elbows, tees, couplings, blowout preventers, wear bushings, reciprocating and/or rotary seal assemblies Dynamic metal-to-metal seals, springs in safety valves, damping joints and jars, logging tool arms, side bags, mandrels, packer slips, packer locks, sand probes, well Flow meters, non-cylindrical components of sand screens, and combinations of the above. 81. The coated sleeved oil and gas well production device of claim 45, wherein said one or more sleeves comprise metal, metal alloy, ceramic, cermet, polymer, carbon steel, steel alloy , stainless steel, WC-based hard metal or a combination of the above. 82. A method of using a coated sleeved oil and gas well production device comprising: A coated oil and gas well production device is provided, the coated oil and gas well production device comprising: one or more cylindrical bodies; and one or more sleeves, wherein the one or more sleeves are tubular components designed to fit over another component; and on the inner sleeve surface of the one or more sleeves, the outer a coating on at least a portion of the barrel surface or a combination thereof, wherein the coating is selected from the group consisting of fullerene-based composites, diamond-like carbon (DLC), and combinations thereof, wherein the coating has a coefficient of friction less than or equal to 0.15, and the coating provides a hardness greater than 1000 VHN, as well as The coated sleeved oil and gas well production devices are utilized in well construction, well completion or production operations. 83. The method of claim 82, wherein the one or more cylindrical bodies comprises two or more cylindrical bodies that move relative to each other. 84. The method of claim 82, wherein the one or more cylindrical bodies comprises two or more cylindrical bodies that are stationary relative to each other. 85. The method of claim 83 or 84, wherein the two or more cylindrical bodies comprise two or more radii. 86. The method of claim 85, wherein the two or more cylindrical bodies comprise one or more cylindrical bodies substantially within one or more other cylindrical bodies. 87. The method of claim 85, wherein the two or more radii have substantially the same size or substantially different sizes. 88. The method of claim 85, wherein the two or more cylindrical bodies border each other. 89. The method of claim 85, wherein the two or more cylindrical bodies do not border each other. 90. The method of claim 88 or 89, wherein the two or more cylindrical bodies are coaxial or non-coaxial. 91. The method of claim 90, wherein the two or more non-axial cylindrical bodies have generally parallel axes. 92. The method of claim 82, wherein the one or more cylindrical bodies are helical in the inner surface, helical in the outer surface, or a combination thereof. 93. The method of claim 82, wherein the one or more cylindrical bodies are solid, hollow, or a combination thereof. 94. The method of claim 82, wherein the one or more cylindrical bodies comprise an outer cross-section, an inner cross-section, or an inner and outer cross-section that is generally circular, generally elliptical or at least one cylindrical body of substantially polygonal shape. 95. The method of claim 82, wherein the coating provides at least 3 times greater wear resistance than an uncoated device. 96. The method of claim 82, wherein the coating has a water contact angle greater than 60 degrees. 97. The method of claim 82, wherein the coating provides a surface energy of less than ¹ J/m2. 98. The method of claim 82, wherein the coating comprises a single coating layer or two or more coating layers. 99. The method of claim 98, wherein the two or more coating layers have substantially the same or different coatings. 100. The method of claim 98, wherein the thickness of the single coating layer and the thickness of each of the two or more coating layers range from 0.5 microns to 5000 microns. 101. The method of claim 98, wherein the coating further comprises one or more buffer layers. 102. The method of claim 101, wherein the one or more buffer layers are disposed on the surface of the one or more cylindrical bodies and the single coating layer or the two or more between coating layers. 103. The method of claim 101, wherein the one or more buffer layers are selected from the group consisting of elements, alloys, carbides, nitrides, carbon-nitrides, and oxides: silicon, titanium, chromium, tungsten , tantalum, niobium, vanadium, zirconium or hafnium. 104. The method of claim 82, wherein the coating has a dynamic coefficient of friction that is no less than 50% of the coating's static coefficient of friction. 105. The method of claim 82, wherein the coating has a dynamic coefficient of friction greater than or equal to the coating's static coefficient of friction. 106. The method of claim 82, wherein the one or more cylindrical bodies further comprise stiffening on at least a portion thereof. 107. The method of claim 106, wherein the hardbanding comprises a cermet-based material, a metal-matrix composite, or a hard metal alloy. 108. The method of claim 82 or 106, wherein the one or more cylindrical bodies further comprise a surface disposed on the one or more cylindrical bodies and at least a portion of the cylindrical bodies. A barrier layer between coatings or hardbanding on top. 109. The method of claim 108, wherein the barrier layer comprises stainless steel or a nickel-based alloy. 110. The method of claim 82, wherein the one or more cylindrical bodies further comprise threads. 111. The method of claim 110, wherein at least a portion of the threads are coated. 112. The method of claim 110 or 111, further comprising a sealing surface, wherein at least a portion of the sealing surface is coated. 113. The method of any one of claims 82, 83 or 84, wherein the one or more cylindrical bodies are well construction devices. 114. The method of claim 113, wherein the well construction device is selected from the group consisting of: drill pipe, casing, tubing string, wire rope/braided rope/multicore conductor/single conductor/well test slickline, coiled tubing Vane rotors and stators for progressive chamber and progressive cavity pumps, expandable pipe fittings, expansion mandrels, centralizers, contact rings, flushing piping, shaker screens for solids control, overshots and grapples, subsea risers, surface Flow lines and combinations of the above. 115. The method of any one of claims 82, 83, or 84, wherein the one or more cylindrical bodies are completion and production devices. 116. The method of claim 115, wherein the completion and production device is selected from the group consisting of: a plunger lift device; a completion sliding sleeve assembly; coiled tubing; a suction rod; a tubing string; ; stuffing boxes; sealers and lubricators; pistons and piston liners; vane rotors and stators for progressive cavity pumps; expandable tubing; expansion mandrels; control lines and conduits; Braided Rope/Multicore Conductor/Single Conductor/Well Test Wire; Centralizers; Contact Rings; Perforated Substrates; Slotted Substrates; Screen Substrates for Sand Control; Flush Pipes; Service tools for isolation operations; wear joints; sand screens placed in completion intervals; sand screens with redundant sand control and barrier compartments; sintered screens; wire wound screens nets; shaker screens for solids control; overshots and grapples; subsea risers; surface flow lines; oil production process lines, and combinations of the above. 117. The method of claim 82, wherein the diamond-like carbon (DLC) is applied by physical vapor deposition, chemical vapor deposition, or plasma assisted chemical vapor deposition coating techniques. 118. The method of claim 117, wherein the physical vapor deposition coating method is selected from the group consisting of: RF-DC plasma reactive magnetron sputtering, ion beam assisted deposition, cathodic arc deposition, and pulsed laser deposition. 119. The method of claim 82, wherein the one or more cylindrical bodies are pin or socket connections of a plumbing tool joint. 120. The method of claim 119, wherein the one or more cylindrical bodies are configured with a proximal cylindrical cross-section that is circular in cross-section. 121. The method of claim 119, wherein the one or more cylindrical bodies are configured with a proximal cylindrical cross-section that is non-circular in cross-section. 122. The method of claim 119, wherein the pin or socket connection is oriented such that the pin faces upward and the socket faces downward relative to the direction of gravity. 123. The method of claim 119, wherein the pin or socket connection is oriented such that the pin faces downward and the socket faces upward relative to the direction of gravity. 124. The method of claim 82, wherein the one or more sleeves comprise metal, metal alloy, ceramic, cermet, polymer, carbon steel, steel alloy, stainless steel, WC-based hard metal, or the foregoing The combination. 125. A method of using a coated sleeved oil and gas well production device comprising: A coated oil and gas well production device is provided, the oil and gas well production device comprising: one or more bodies, wherein the one or more bodies do not include a drill bit; and one or more sleeves near the surface or inner surface, wherein the one or more sleeves are tubular components designed to fit over another component; and within the one or more sleeves a coating on at least a portion of the surface of the sleeve, the surface of the outer sleeve, or a combination thereof, wherein the coating is selected from the group consisting of fullerene-based composites, diamond-like carbon (DLC), and combinations thereof, wherein the coating has a coefficient of friction less than or equal to 0.15, and the coating provides a hardness greater than 1000 VHN, as well as The coated sleeved oil and gas well production devices are utilized in well construction, well completion or production operations. 126. The method of claim 125, wherein the one or more bodies comprises two or more bodies that move relative to each other. 127. The method of claim 125, wherein the one or more bodies comprise two or more bodies that are stationary relative to each other. 128. The method of claim 125, wherein the one or more bodies further comprise spherical or complex geometric shapes. 129. The method of claim 128, wherein the complex geometric shape has at least a portion that is a non-cylindrical shape. 130. The method of claim 126 or 127, wherein the two or more entities comprise one or more entities substantially within one or more other entities. 131. The method of claim 126 or 127, wherein the two or more bodies border each other. 132. The method of claim 126 or 127, wherein the two or more bodies do not border each other. 133. The method of claim 126 or 127, wherein the two or more bodies are coaxial or non-coaxial. 134. The method of claim 125, wherein the one or more bodies are solid, hollow, or a combination thereof. 135. The method of claim 125, wherein the one or more bodies comprise an outer cross-section, an inner cross-section, or an inner and outer cross-section that is generally circular, generally elliptical, or generally At least one body of the upper polygon. 136. The method of claim 125, wherein the coating provides at least 3 times greater wear resistance than an uncoated device. 137. The method of claim 125, wherein the coating has a water contact angle greater than 60 degrees. 138. The method of claim 125, wherein the coating provides a surface energy of less than ¹ J/m2. 139. The method of claim 125, wherein the coating comprises a single coating layer or two or more coating layers. 140. The method of claim 139, wherein the two or more coating layers have substantially the same or different coatings. 141. The method of claim 139, wherein the thickness of the single coating layer and the thickness of each of the two or more coating layers range from 0.5 microns to 5000 microns. 142. The method of claim 139, wherein the coating further comprises one or more buffer layers. 143. The method of claim 142, wherein the one or more buffer layers are disposed on the surface of the one or more bodies and the single coating layer or the two or more coating layers between cladding. 144. The method of claim 142, wherein the one or more buffer layers are selected from the group consisting of elements, alloys, carbides, nitrides, carbon-nitrides, and oxides of silicon, titanium, chromium, tungsten , tantalum, niobium, vanadium, zirconium or hafnium. 145. The method of claim 125, wherein the coating has a dynamic coefficient of friction not less than 50% of the coating's static coefficient of friction. 146. The method of claim 125, wherein the coating has a dynamic coefficient of friction greater than or equal to the coating's static coefficient of friction. 147. The method of claim 125, wherein the one or more bodies further comprise hardbanding on at least a portion thereof. 148. The method of claim 147, wherein the hardbanding comprises a cermet-based material, a metal-matrix composite, or a hard metal alloy. 149. The method of claim 125 or 147, wherein said one or more bodies further comprises said coating disposed on a surface of said one or more bodies and on at least a portion of said bodies Or the isolation layer between hardened layers. 150. The method of claim 149, wherein the barrier layer comprises stainless steel or a nickel-based alloy. 151. The method of claim 125, wherein the one or more bodies further comprise threads. 152. The method of claim 151, wherein at least a portion of the threads are coated. 153. The method of claim 151 or 152, further comprising a sealing surface, wherein at least a portion of the sealing surface is coated. 154. The method of any one of claims 125, 126, or 127, wherein the one or more bodies are well construction devices. 155. The method of claim 154, wherein the well construction device is selected from the group consisting of: chokes, valves, valve seats, chokes, ball valves, annular isolation valves, subsurface safety valves, centrifuges, elbows, tees , couplings, blowout preventers, wear-resistant bushings, dynamic metal-to-metal seals in reciprocating and/or rotating seal assemblies, springs in safety valves, damping joints and jars, logging tool arms, rig slides Shifting devices, pawls, and combinations of the above. 156. The method of any one of claims 125, 126, or 127, wherein the one or more bodies are completion and production devices. 157. The method of claim 156, wherein the completion and production device is selected from the group consisting of: chokes, valves, valve seats, chokes, ball valves, inflow control devices, smart well valves, annular isolation valves, subsurface safety valves , centrifuges, gas lift and chemical injection valves, elbows, tees, couplings, blowout preventers, wear bushings, dynamic metal-to-metal seals in reciprocating and/or rotating seal assemblies, safety valves Springs, damping joints and jars, logging tool arms, side bags, mandrels, packer slips, packer locks, sand probes, well flow meters, sand screens Cylindrical components, and combinations of the above. 158. The method of claim 125, wherein the diamond-like carbon (DLC) is applied by physical vapor deposition, chemical vapor deposition, or plasma-assisted chemical vapor deposition coating techniques. 159. The method of claim 158, wherein the physical vapor deposition coating method is selected from the group consisting of: RF-DC plasma reactive magnetron sputtering, ion beam assisted deposition, cathodic arc deposition, and pulsed laser deposition. 160. The method of claim 125, wherein the one or more sleeves comprise metal, metal alloy, ceramic, cermet, polymer, carbon steel, steel alloy, stainless steel, WC-based hard metal, or the foregoing The combination.