Solid metal wear band for downhole tubulars, product and process

Abstract

Protection of tubulars from premature wear in the mid-body section due to highly curved wellbores, including bowing from high axial compressive loads, or gravity induced bowing in a horizontal section of the wellbore is disclosed. It includes a method of installing a strong, wear resistant, fully encircling steel band around the midbody region of tubular joints on new and worn tubulars. Further, it does so without degrading the metallurgy or microstructure of the pipe body yet attaches the protective band with such high clamping force that it is unlikely to slip even under the most extreme service conditions. In addition, the circumferential integrity of the pipe band makes it even less likely to ever break off. A protective band includes a wear resistant hard banding weld overlay installed around the circumference of the protective band.

Description

Solid Metal Wear Band for Downhole Tubulars, Product and ProcessTECHNICAL FIELD

[0001] The present disclosure relates to the protection of tubulars from premature wear in the mid-body section due to highly curved wellbores, bowing from high axial compressive loads, or gravity induced bowing in the horizontal section of the wellbores.BACKGROUND

[0002] Protection of tubulars from premature wear in the mid-body section due to highly curved wellbores, bowing from high axial compressive loads, or gravity induced bowing in a horizontal section of the wellbores is challenging. Proposed solutions exist but most have undesirable limitations. Therefore, there is opportunity for improvement. The following discussion is not an admission that any product or cited reference discussed is prior art to the disclosure or part of the knowledge of persons skilled in the art. Nor is the discussion intended to be a full and complete description of the disclosed products or all potential prior art in general.

[0003] There are existing protective devices to prevent abrasion degradation of tubulars, particularly around the midpoint of the pipe body. To date there have been limited commercially available choices, including; a) bolt something onto the outside diameter (OD) of the tubular; b) weld, spray, or adhere something onto the OD of the tubular; or c) cut the tubular in half and weld a new thick section into the middle of the tubular.

[0004] Bolted on devices, including for example a device by OSI Regal series, Petrosynch, as described inUnited States Patent No. 8,668,007, titled Non-rotating Casing are inherently limited to a maximum joint efficiency of about 20% of their full cross section thickness. Also, for most designs, the higher the clamping force they are installed with, the more likely they are to break apart and fall downhole. Failure of bolted on devices and the associated debris falling off downhole commonly leads to stuck tubular strings with a cost typically over a million dollars in United States Dollars (USD) per event. For this reason, the use of bolted on devices has not been widely accepted in the industry.

[0005] Hard banding welded directly onto a tubular body, for example by Spiralband degrades the strength of the tubular and creates many new potential fracture initiation sites. Additionally, products such as Spiralband limit the sealability of well control equipment on the tubular, restricting the use of managed pressure techniques which are common in the industry.

[0006] Thicker cross section spool pieces, for example RDT’s WearKnot® welded into the middle of the tubular body are similar to adding another mid-body tool joint. This is a very expensive solution that can only be done in a large factory with huge, expensive machines including friction welders, big bore computer numerical control (CNC) lathes, induction heat treating systems, pipe handling systems, etc.

[0007] Besides the foregoing commercially available products, the United States Patent and TrademarkOffice and international patent offices have records of many proposed solutions to the problem of midsection wear on downhole tubulars. Most involve multiple components which are screwed or glued or bolted together, sometimes involving taper wedge components and / or glue to increase grip on the tubular. Some involve welding but none appear to achieve full body strength of a solid steel ring without risking metallurgical degradation of the tubular body and achieving adequately high grip to the tubular, nor do they appear to incorporate hard banding.

[0008] Some of the U.S. patents and patent publication describing downhole tubular wear bands can be found in the following discussion:

[0009] Metal Sleeve of Two Semi-Cylindrical Parts Welded Together

[0010] Metal wear sleeves have been formed of two semi-cylindrical pieces welded together and secured about a tubular in various ways using an elastic intermediary layer between the metal sleeve and the tubular disclosed by the following patents: U.S. Pat. No. 2,259,023 — Clark (rubber between tubular and sleeve. Sleeves are subsequently clamped and longitudinally welded); U.S. Pat. No. 2,295,873 — Stone (rubber bonded between pipe and sleeves); U.S. Pat. No. 2,877,062 — Hall et al (metal strips acting as springs between tubular and sleeve); and U.S. Pat. No. 3,697,141 — Garrett (rubber insert between sleeve and tubular). The primary difficulty with elastic intermediary layers is that it is difficult to achieve the necessary bond strength between the band and the tubular to prevent slippage of the band downhole.

[0011] Metal Sleeve of Two Semi-Cylindrical Parts Bonded Directly to the Tubular

[0012] The concern over bond strength has been addressed through the method of directly welding the sleeve to the tubular, or use of an adhesive compound between the sleeve and tubular as disclosed in the following patents: U.S. Pat. No. 2,281,632 - Steps (sleeve which is clamped and longitudinally welded, and also welded to tubular); U.S. Pat. No. 3,667,817 - Kellner (fabric reinforced resinous insert between sleeve and tubular); U.S. Pat. No 4,499,924 - Garrett (fracturing a sleeve into two matching halves which may be fixed to a tubular through the use of adhesive cement such as epoxy resin and longitudinally welded to each other); U.S. Pat. No. 4,146,060 - Garrett (adhering a sleeve to a tubular through the use of an adhesive polymeric material); and G.B. Pat. No. 2,131,725 - Garrett (sleeve which clamped and longitudinally, and also welded to tubular.)

[0013] The effectiveness of adhesive compounds to retain the sleeve to the tubular has been found to be poor due to the high cyclical loading of tubulars downhole, vibration, and changes in temperature and geometry of the tubular under load. Directly welding the sleeve to the tubular is effective in maintaining the strength of the bond and position of the sleeve on the tubular, however the heat affected zone that is inherent when directly welding to the tubular compromises the metallurgical integrity of the tubular and has resulted in premature fracturing and failure.

[0014] Mechanically Retained Integral Metal Sleeve

[0015] It is also known to secure an integral steel sleeve about a tubular member by various means, the member having at least one end free of upset so that the sleeve can pass thereover, as shown by the following United States patents: U.S. Pat. No. 2,318,878 - Miller (oversize steel sleeve disposed about stretched on rubber jacket and positioned by welded split end rings.) Note: Jacket can turn inside sleeve. U.S. Pat. No. 2,855,052 — Wright et al (wedge rings inside steel sleeve.) Note: Sleeve is split and welded if tubular is upset on both ends. U.S. Pat. No. 3,276,824 — Carter (steel sleeve held in place by wedges.) Note: Sleeve is secured to stabilizer mandrel to retain stabilizer sleeve. U.S. Pat. No. 3,411,837 — Schellstede (two internally tapered rings drawn together by weld tension wedge against internal split wedge ring.) U.S. Pat. No. 3,482,889 — Cochran (stabilizer body wedged to drill collar with slips.) Mechanically retained integral metal sleeves deal with the issues of bond integrity between the sleeve and tubular without compromising the metallurgy of the tubular but are not usable on tubulars with upsets on both ends.

[0016] Integral Enlargement

[0017] It is also known to employ an integral enlargement in a tubular in between the tool joint ends, as shown by the following United States patents: U.S. Pat. No. 3,484,122 — Schellstede et al. U.S. Pat. No. 3,773,359 — Chance et al. U.S. Pat. No. 3,784,238 — Chance et al. Integral enlargement wear belts add the equivalent of a tool joint in the center of the pipe without compromising the integrity of the pipe and cannot fall off the pipe. The use of integral wear belts is limited to a factory environment due to the large size of the equipment required to cut, prep, weld, and post weld heat treat. The operation also has a high initial cost of a tube large enough to provide the desired outer diameter for the wear belt plus the cost of turning down the large diameter tube to provide a tubular of the desired wall thickness, flexibility and weight.

[0018] Plastic Deformation of the Sleeve:

[0019] Attaching bands or centralizers through crimping can be found in U.S. Pat. No. 7,082,997. However, these bands are required to be quite thin to be sufficiently crimped and are not able to withstand the mechanical forces applied in typical downhole applications without plastically deforming. Crimping also limits the amount of pressure that can be generated at the interface between the tubular and the sleeve since the compressive stress in the sleeve must be fully reversed before permanent contact pressure is generated. The stiffness of the tubular is typically significantly higher than that of the sleeve and therefore only a small fraction of the initial crimping load will be converted to permanent contact pressure between the tubular and the sleeve.

[0020] Hard banding Directly Applied to Tubular

[0021] Use of helical hard banding applied directly to the tubular can be found in U.S. Pat. No. 1,1286,728.This technique is both cost effective and durable, however directly welding hard banding to a tubular imparts a large amount of heat resulting in a heat affected zone within the tubular having compromised metallurgy because high strength grades of steel are typically used in relevant tubulars. Fatigue or environmental cracking is known to initiate in this heat affected zone resulting in downhole failures of tubulars.

[0022] Molded-On Polymer Wear bands

[0023] U.S. Pat. App. Pub. US20230016216A1 describes a method of protecting a tubing or solid rod component from abrasive wear, comprising the step of forming one or more circumferential wear bands of a selected polymeric material around the tubing or solid rod component at one or more selected locations along the length of the tubing or solid rod component. Polymers generally have tensile strength about an order of magnitude less than steel, therefore are not likely to withstand routine downhole mechanical forces for anywhere near as long as the typical hard banding on the tool joints.

[0024] Differential Thermal Application:

[0025] Of particular interest, attaching the wear band through the use of compressive force induced by cooling of heated sleeve halves, with or without the additional assistance of compressive clamping force can be found in U.S. Pat. Nos. 3,193,918A, 3,360,846A, 3,499,210A, 3,411,837A, 3,193,918A discloses a method of heating two sections of a sleeve and subsequently clamping the sleeve to the tubular member without the weld penetrating the underlying surface of the tubular member. The weld is made between the two sleeve halves on top of an asbestos rope. The high compressive forces imparted through the clamps and cooling of the metal band provide a durable bond betweenthe band and the tubular body. U.S. Pat. No. 3,360,846A discloses a split sleeve which is heated, clamped and longitudinally welded to a tubular using an epoxy resin to cement the sleeve to the tubular. In addition, one or more circumferential welds are placed around the sleeve. As the sleeve cools, it contracts and the welds hold the sleeve in place. U.S. Pat. Nos. 3,499,210A and 3,411,837A disclose a method of heating a one piece longitudinally split sleeve, opening the sleeve to slip it over a tubular end joint, sliding the sleeve to the desired position then allowing the sleeve to close. Subsequently the sleeve is longitudinally welded and allowed to cool, whereby the cooling of the sleeve results in contraction and a compressive force on the tubular.

[0026] The disclosures in U.S. Pat. Nos. 3,193,918A, 3,360,846A, 3,499,210A, and 3,411,837A discuss directly attaching a steel sleeve to the tubular in a robust manner through the use of compressive force. However, all of these disclosures require the use of preheating of the sleeve and subsequent cooling of the sleeve to achieve the required compressive force. The time and cost required to pre-heat the bands is burdensome, and the ability to pre-heat the bands to a consistent temperature may require that the process be performed in a shop setting. Temperatures required to achieve sufficient shrinkage forces are likely to damage or destroy organic linings commonly present in the tube body. Requirements to control the cooling rate are costly and complex to manage in an outdoor environment. Additionally, the compressive forces imparted by the cooling of the band are difficult to quantify and may lead to either over compression of the drill pipe past its elastic limit if the bands are too hot when installed, or not enough compressive strength to provide an adequate bond if the bands are too cold when installed. Furthermore, these steel sleeves do not include a wear resistant overlay which is crucial to durability and longevity of the protective wear band.SUMMARY

[0027] The present disclosure may relate to the protection of tubulars from premature wear in the mid-body section due to highly curved wellbores, including bowing from high axial compressive loads, or gravity induced bowing in a horizontal section of the wellbore. It includes a method of installing a strong, wear resistant, fully encircling steel band around the midbody region of tubular joints on new and worn tubulars. The wear band has full parent metal strength for its entire thickness around the entire circumference and along the length of the band. Further, it achieves these benefits without degrading the metallurgy or microstructure of the pipe body yet attaches the protective band with such high permanent clamping force that it is unlikely to slip even under the most extreme service conditions. In addition, the circumferential integrity of the pipe band makes it even less likely to ever break off. A protective band includes a wear resistant hard banding weld overlay installed around the circumference of the protective band.

[0028] A downhole wear band system is disclosed for use in a downhole application, the downhole wear band system comprising: a downhole tubular formed of a tubular body with tubing connectors at opposed ends of the tubular body; and a wear band formed by a hollow cylindrical shell that is defined by one or more arcuate shell portions that are: spaced between the opposed ends of the tubular body and clamped around the tubular body to elastically deform the tubular body; and longitudinally welded together to retain an elastic deformation of the tubular body.

[0029] A method is disclosed comprising : clamping one or more arcuate shell portions around a tubular body, of a downhole tubular, at a location spaced between opposed ends of the tubular body, with a distributed force sufficient to radially compress the tubular body within an elastic limit of deformation of the tubular body; and longitudinallywelding together the one or more arcuate shell portions to form a wear band around the tubular body and to retain an elastic deformation of the tubular body.

[0030] A downhole wear band system kit is disclosed for use in a downhole application, the downhole wear band system comprising: one or more arcuate shell portions that each have longitudinal edges, and that define downholetubular-contacting inner surfaces; in which the one or more arcuate shell portions are sized to be assembled, in use in a circumferential fashion to form a wear band around a tubular body of a downhole tubular, such that the one or more arcuate shell portions can thereafter be clamped to the downhole tubular and longitudinally welded together to secure the wear band on the downhole tubular; and in which the one or more arcuate shell portions comprise weld overlay hard banding on outer surfaces of the one or more arcuate shell portions.

[0031] It is an objective and advantage of various embodiments of this disclosure to improve the reliability, performance and service life of downhole tubulars, which in many drilling applications are subjected to premature wear and failure due to the middle portion of the tubular being forced into sliding / rotating contact with the abrasive wellbore or casing.

[0032] The present disclosure may provide a way of installing abrasion resistant steel wear bands onto the center portion of standard Oil Country Tubular Goods (OCTG) and similar tubulars at the most common location of wear-induced failure, which normally is at the midpoint of the tubular joint. About 90% of the length of a typical tubular joint is of a smaller diameter than the ends.

[0033] In the case of drill pipe, both ends have enlarged diameter and wall thickness to accommodate robust threaded end connections. The enlarged end portion is known as the “tool joint” and provides greatly increased durability. The tool joint is typically made of a steel grade that is better suited for welding and threading, which, combined with the thick wall allows hard banding to be directly applied to the tool joint. However, this enlarged diameter at the ends also makes it difficult to slide a close-fitting band onto the pipe body where it could otherwise be crimped in place near the midpoint. Additionally, the variance in diameter and eccentricity of most drill pipe body tubulars would require a large clearance between the pipe body and an integral band which makes heat-expansion impractical and significantly complicates a crimping process, even if applied to new drill pipe before tool joint installation. Commercially available wear bands (collars, rings, etc.) for drill pipe lack the robustness and reliability sought by the drilling contractors and their clients. The only commercially available “strong” solution which does not compromise the integrity of the pipe body or risk pieces falling off downhole and causing the drill string to become stuck is to manufacture the original drill pipe with a thick upset in the middle (ref RDT’s WearKnot®).

[0034] Elements of a typical specific example of the present disclosure applied to the example of 102mm drill pipe with pre-applied hard banding are:

[0035] Mild steel tube stock with inner diameter (ID) closely matched to the OD of the intended drill pipe and about 9mm wall thickness is weld surfaced with gas metal arc welding (GMAW) hard banding (for example Duraband NC®) in circumferential strips about 25mm wide, in three adjacent passes to form a contiguous wear resistant band having about 75mm total axial length. These bands are repeated at about 200mm intervals until a convenient length of hard banded tube stock is completed.

[0036] The hard banded tube stock is laser or plasma or waterjet cut or machined in a tube cutting system having at least a rotary axis and a longitudinal axis, producing half shells about 200mm long.

[0037] Longitudinal edges of the half shell pairs are machined or ground or laser cut or waterjet cut or plasma cut to provide an ideal root gap of about 2mm with a Vee groove included angle of about 30 degrees. In some cases, included angles of between 0 and 90 degrees may be used.

[0038] Two matching half shells are placed at the desired axial position on the OD of the drill pipe with tungsten metal barrier strip (about 0.2mm x 9mm x 200mm) centered under the root gap of both longitudinal seams forming a barrier between the weld and the drill pipe OD.

[0039] Half shells are clamped onto the drill pipe. The clamping force generates compressive hoop stress within the drill pipe optimized for the particular application, typically anywhere in the range of 10% to 80% of compressive yield for the particular drill pipe size and grade.

[0040] Fast, shallow (about 2mm to 4mm deep) root pass weld joins the half shells and provides thermal barrier for subsequent fdl pass to ensure there is no degradation of the underlying drill pipe. As part of the clamping procedure, a thin tungsten strip is located between the half shells and the drill pipe as a barrier to prevent the root pass weld from making contact with the drill pipe. The tungsten strip may only need to be about 0.25mm thick to prevent the root pass from penetrating to the surface of the drill pipe with a 2mm width GMAW root pass. The thinness of the barrier that is achievable with a tungsten or refractory metal strip is a substantial improvement in the reliability of protection afforded to the drill pipe and an improvement in the weld joint strength over the prior art.

[0041] Slower fill / cap pass fills in the remaining depth (about 5mm - 7mm) of the Vee groove to the OD surface of the 9mm thick half shells. Multiple fill / cap passes may be required depending on the depth and width of the Vee groove.

[0042] If the tungsten barrier strip is recessed in an ID step in the half shells, the completed weld achieves about 90% or greater of full penetration in joining the half shells. Since the GMAW fdler can be overmatched to the yield strength of the mild steel clamshells, the effective joint efficiency may be over 90%.

[0043] For the remaining 3mm of added thickness at the band which was overlaid on the tube stock with weld hard surfacing, a short longitudinal cap pass of the same hard surfacing alloy may be welded on to bring that portion up to the OD of the hard band. Alternatively, Step 7 may fully fill the weld prep vee groove to the OD of the hard facing.

[0044] While clamping force is retained, the clamping assembly and tubular is rotated to align the second longitudinal weld with the welder, which is typically oriented approximately to the high side, and the second longitudinal weld is made in a similar manner.

[0045] The combined thickness of 9mm plus 3mm brings the OD of the wear band, including hard banding, to about equal with the OD of the tool joint for most modem 102mm drill pipe joints, making these the optimal dimensions to eliminate midbody wear without protruding beyond the diameter of the tool joints. Older versions of drill pipe tend to have a larger tool joint diameter for the same pipe body diameter, in which case the aforementioned 9mm thickness of the half shells could be increased accordingly which may beneficially provide additional strength or thickness for wear resistance.

[0046] It is also evident that the thickness ratio of the half shell versus the hard banding can be adjusted. It may be desirable that the OD surface of the hard banding on the wear band closely matches the OD of the tool joint, or it may be desirable for the hard banding on the wear band to be smaller than the OD of the tool joint. For example, if especially abrasive downhole conditions are expected, then the thickness of the hard banding can be increased while decreasing the thickness of half shells. Alternatively, for increased longevity in abrasive conditions, the number of hard banding rings can be increased from the usual three (3) side by side, 25mm wide rings, up to as many as can fit on the overall half shell length, which typically will be about 200mm long.

[0047] For the following disclosures, there are multiple nonlimiting embodiments being contemplated, because the present disclosure could be used in different applications with wide ranging operating environments. Thus, it is not possible for a single preferred embodiment to be optimal for all applications.

[0048] In some nonlimiting embodiments, the wear band may comprise two half shells which may be clamped around the outer diameter of a tubular and longitudinally welded to form a robust wear band. In other embodiments, the wear band may comprise a sleeve with a single longitudinal split which is which is opened to allow the wear band to slide over ends of tubulars that do not have large tool joints at the end; this opening may result in elastic and / or plastic deformation of the band prior to and during the clamping and longitudinal welding process.

[0049] In some nonlimiting embodiments, the wear band may comprise low carbon steel which may be preferable for welding, as it does not require a preheat prior to longitudinal seam welds or during hard banding weld overlay. The wear band may be approximately 200mm in length, but may be greater than or less than this depending on the service conditions, slip force and clamping force requirements. Increasing the length of the wear band increases the slip force required to move the wear band axially along the tubular it is mounted to for any given clamping force used for mounting the tubular. In some scenarios it may be desirable to use a low clamping force in order to impart minimal residual stress on the tubular such as when the tubular is casing; which may see high collapse loads when in service which would be undesirable to compound with high radial compressive loads from the wear band. Reducing the length of the wear band reduces the slip force required to move the wear band axially along the tubular it is mounted to for any given clamping force used to mount the tubular. However, a reduced length wear band may be desirable in situations where the tubular will be utilized in wells with high dogleg severities where the bending stress imparted to the tubular due to a long rigid wear band may lead to fatigue related failures of the tubular. In such situations it may be desirable to stack multiple shorter wear bands adjacent to each other to provide increased slip strength to adjacent wear bands, but also reduce the rigidity of the tubular assembly and the likelihood of fatigue failures when compared to a single band of the same length.

[0050] In some nonlimiting embodiments, the wear band may have a thickness greater than or less than 9mm depending on the tubular outer diameter, tool joint outer diameter and the borehole inner diameter. It may be desirable that the thickness of the wear band is less than the difference between the borehole inner radius and the outer radius of the tubular. If a sleeve without blades or external features is used for the wear band, it may be desirable that the thickness of the wear band is less than the difference between the tool joint outer radius and the tubular outer radius, to ensure that the wear band does not protrude beyond the radius of the tool joint and provide a point which may hang up the tubular string in the borehole. If a sleeve with blades or external features is used for the wear band, it may be desirable that theouter diameter of the wear band after it has been mounted to the tubular is approximately equal to, or slightly less than the inner diameter of the borehole. The outer diameter of the wear band may range from 4mm to 40mm larger than the outer diameter of the tubular.

[0051] In some nonlimiting embodiments the half shells may be manufactured with an inside surface circumference being approximately equal to or slightly less (typically between 10mm less to 0.1mm less) than one-half of the tubular outer circumference at the intended installation location. The half shells may be manufactured with an inside surface radius slightly less than or approximately equal to or slightly larger than (between 10mm less to 20mm more) the outside radius of the tubular at the intended installation location.

[0052] The half shells may be manufactured with assorted internal diameters and / or assorted internal circumferences to accommodate various tubular outer diameter sizes for use on new or used tubulars. The tubular outer diameter may range from 25mm to 500mm for most commonly encountered applications, but there is no limitation of the present disclosure being adapted to much larger diameters. The half shell internal diameter increments or internal circumference increments may be between 0.1mm to 10mm. In some embodiments the longitudinal edges of each half shell may be profiled for welding with a root gap between zero mm and 10mm when the half shells are clamped. The initial root gap may be sufficiently large at both of the diametrically opposite V grooves to allow compression of the tubular without contact of the opposing half shells at the root of the V grooves.

[0053] In some nonlimiting embodiments the wear band may be installed without the use of fillers or adhesives between the wear band and the tubular. The wear band may be installed directly to the outer diameter of the tubular with metal-to-metal contact. The internal diameter of the wear band may be roughed up, or may be precoated with a hard or abrasive coating to increase the friction coefficient between the band and the tubular. The wear band internal diameter may be precoated with a soft metal such as phosphating or galvanizing, or with a fdler substance such as thread compound to avoid fluid invasion between the wear band and the tubular which may lead to corrosion. Alternatively, Teflon or rubber seals may be placed at either end of the wear band between the wear band and the tubular prior to clamping to prevent fluid invasion. Sandblasting, pressure washing, belt sanding, laser ablation or other similar methods may be used to clean and / or roughen the tubular outer surface prior to mounting the band on the tubular.

[0054] In some nonlimiting embodiments, slots may be present between portions of the wear band and the tubular to allow for free movement of fluid to limit stagnation of fluid which may invade space and lead to corrosion. These slots may be formed either by grooves in the half shells or by separate spacer components located between the half shells and tubular. Even if fluid invasion and stagnation were to occur, galvanic corrosion of the tubular in the interstitial space between the band and the tubular may be mitigated through use of a low alloy grade for the half shells which provide mild cathodic protection to the tubular.

[0055] In some nonlimiting embodiments clamping force may be sufficient to radially compress the tubular between 10% and 100% of its elastic limit. The clamping force may be maintained, monitored and / or adjusted while the longitudinal weld(s) are applied and cooled to ensure it is kept between 10% and 100% of the tubulars elastic limit. The clamping force required to radially compress the tubular to a certain stress relative to its elastic limit may be empirically determined by testing on samples of the actual tubular and band and welding consumables. Finite Element Analysis (FEA) of clamping forces may be calibrated and used to determine optimal clamping and welding parameters for newsizes, weights, and grades of tubular. The empirical testing and FEA modelling may ensure that the additive effects of the clamping force plus the weld shrinkage remains below 100% of the elastic limit for radial compression of the tubular body. Additionally, it may be beneficial to ensure that the clamping force is sufficient to allow a complete seam weld to be completed on the initial side chosen for longitudinal welding and the weld subsequently partially or fully cooled without the weld shrinkage shifting the half shells and widening the root gap on the opposite side of the half shells.

[0056] In some nonlimiting embodiments, a backing strip may be located between the tubular and a longitudinal weld in order to reduce the heat observed by the tubular during the longitudinal welding process. The backing strip may comprise of highly thermal conductive and / or thermally resistant materials to allow for heat dissipation such as tungsten, tungsten carbide, tungsten alloy, silver, copper, aluminum nitride, silicon carbide, graphite, ceramic, etc. The longitudinal edges of the backing strips may be beveled to reduce the interstitial space between the tubular and the wear band to limit the amount of fluid invasion and potential corrosion. The half shells may have a uniform radius on the inner surface without a step cut into them for the backing strip. Alternatively, the backing strip may have a thickness profile matching a non-uniform thickness profde of a gap formed between the half shells and the tubular. The backing strip may have a width greater than the root gap of the longitudinal weld to ensure that the weld material does not come into direct contact with the tubular. The backing strip may have a thickness between 0.05mm and 0.5mm. The backing strip must be of adequate thickness to provide heat dissipation and prevent metallurgical impact and weld arc contact to the tubular as a result of the longitudinal weld, however limiting the thickness allows for increased weld penetration and joint strength between the half shells. The backing strip may have a width between 2mm and the full circumference of the tubular. During the first root weld pass of the clamped half shells, the power input and travel speed of the root pass may be controlled to allow for the weld material to fully penetrate the V groove without melting through the backing strip. In some embodiments, accelerated cooling of the longitudinal seam welds may be performed using air, water, or other fluids to protect an internal coating of the tubular, which may otherwise be degraded by elevated temperatures of the longitudinal seam weld. Through extensive testing, it is not believed that accelerated cooling of the longitudinal seam welds is required, as use of an adequate backing strip and optimized weld parameters has been found to result in no longitudinal weld thermal damage to tubular internal coatings.

[0057] In some nonlimiting embodiments, the half shells may have a hard banding weld overlay treatment applied to the half shells prior to being mounted to the tubular. This may be advantageous as the manufacturing and hard banding of the half shells may be done in a factory type setting to reduce costs and improve the quality of the hard band. Another potential advantage of hard banding the half shells prior to mounting them to the tubular is that in this scenario, the heat input from the hard banding process is not experienced by the tubular which reduces the likelihood of heat damage to the tubular’s internal coating. When the hard banding overlay is applied to the half shells prior to mounting them onto the tubular, the cap pass of the longitudinal welds may extend to the full diameter of the hard banding overlay, and may comprise a hard facing alloy. If a hard face alloy is used for the cap pass it may only be applied over the portion of the seam weld where the hard banding overlay is present.

[0058] In some nonlimiting embodiments, the hard banding overlay treatment may be applied to the wear band after it has been mounted on the tubular. This hard banding may occur immediately after the wear band has been mounted on the tubular, or applied / re-applied after the tubular and wear band have been in service and the hard bandinghas been worn to the point of needing replacement. An advantage of the present disclosure is that weld hard surface overlay can be applied onto the installed half shells at any point in their service life without weld preheating, yet without risk of metallurgical damage to the underlying tubular body. The hard banding overlay may consist of a single circumferential band, multiple circumferential bands either adjacent to each other or spaced out from each other. The hard banding overlay may consist of helical spirals or longitudinal strips, or other patterns or combinations thereof. The embodiment may consist of multiple circumferential bands in order to provide a round outer diameter for any radial cross section in order to provide the ability to seal on the wear band with well control equipment such as blow out preventers or managed pressure drilling rotating heads. The hard banding overlay may provide increased wear resistance for the wear band when in contact with and reciprocated or rotated against abrasive boreholes. Such circumferential bands may be spaced out in order to reduce the heat input to a certain concentrated area of the tubular due to the weld overlay hard banding process, reducing the heat effect on the tubular and its internal coating.

[0059] In some nonlimiting embodiments, the hard banding may have a lower coefficient of friction than the tubular in order to reduce the friction between the tubular string and the borehole. The hard banding may comprise a single material, alloy or composite, or multiple dissimilar weld materials in order to both reduce friction and improve wear resistance. A typical hard banding which is currently used for wear resistance on tubulars such as drill pipe tool joints is Duraband NC®, and may also be used for hard banding the wear band. Duraband NC® is a re-buildable hard banding wire made from a steel matrix with a high volume of tightly packed micro-constituents. Multiple different types of hard banding overlays may be applied to the same wear band such as both Duraband NC® for wear resistance and Tuboscope’s TCS-Titanium™ hard banding for reduced friction. Tuboscope TCS-Titanium™ is a martensitic chrometitanium carbide alloy with molybdenum, which provides high-stress abrasion resistance and the ability to resist cracking and spalling. In some embodiments, the half shells may have pre-installed features on the outer diameter prior to mounting to the tubular which may be mechanically retained elements which are inserted from the ID or molded in place such as tungsten carbide tiles or polycrystalline diamond compact cutters, for example to act as a hole reamer tool. In some embodiments, the wear band may be mounted on drill pipe. Drill pipe is typically rotated at high RPM and reciprocated in downhole environments consisting of abrasive formations, large doglegs, high side forces and in lateral or high inclination applications resulting in significant amounts of pipe body wear. In other embodiments, the wear band may be mounted on casing, tubing, downhole drilling tools, or rods for downhole pumps; all of which are negatively affected by high friction, observe wear in downhole environments, and may benefit from improved rigidity, borehole standoff and more even fluid flow.

[0060] In some nonlimiting embodiments, pre-installed features applied to the half shells prior to mounting to the tubular may comprise of injection molded polymer. This polymer may serve multiple purposes; to act as a low friction interface between the wear band and the borehole, to reduce casing wear when the wear band contacts casing, to act as a shock absorber to reduce lateral shocks to the tubular which may comprise sensitive downhole electrical components such as steering assemblies, or measurement tools. It is anticipated that polymer will rapidly wear when placed downhole due to abrasive contact with the borehole, as such it may be desirable to have a wear resistant contact on the wear band which may contact the borehole after the polymer has worn to a certain point to prevent further wearto the polymer. Once the polymer has worn to such a point, it may be possible to remove the wear bands on which the polymer was pre-installed and mount a new wear band with pre-installed polymer to the tubular.

[0061] In some nonlimiting embodiments, the wear band may comprise a bladed outer surface, with straight or spiral blades. Slots between blades may provide a bypass area to allow for free movement of fluid past and around the wear band. The blades may provide a contact point between the tubular and the borehole which may serve many beneficial purposes such as; a) allows more efficient weight transfer from surface to the bottom of the tubular string due to increased rigidity and reduced buckling of said tubular string, increases standoff between the tubular and the borehole which may assist in reducing tubular surface area in contact with the borehole and the potential for differential sticking, b) increases standoff between the tubular and the borehole to provide more even fluid flow around the tubular for improved cement displacement, c) provides standoff between the tubular and the borehole to assist in borehole cleaning at inclinations greater than about 15 degrees off vertical, d) provides standoff between the tubular and the borehole to improve cuttings removal and reduce the cuttings bed height in highly deviated or horizontal wells while drilling or circulating, reduces contact between the tubular body and the borehole to reduce pipe body wear, e) reduces contact between the tubular body and the borehole to reduce friction, f) improves the condition of the borehole by providing edges or features to wipe the borehole as the tubular string is rotated or reciprocated, g) improves the condition of the filter cake on the internal surface of the borehole by providing edges or features to wipe the fdter cake as the tubular string is rotated or reciprocated stabilize the tubular to reduce buckling and / or vibration of the tubular string, h) provides borehole contact points part way along drilling, measurement-while-drilling or logging-while-drilling components in order to reduce vibration or undesirable bending dynamics of a drilling assembly, i) reduces friction between the tubular string and the borehole due to reduced contact area between the tubular string and the borehole and / or due to the wear band outer surface having a lower coefficient of friction than the tubular outer diameter. If installing the wear band in proximity to directional sensors, it may be beneficial to use a non-magnetic steel alloy, for example austenitic stainless steel for both the half shells and the weld filler material as well as weld overlay material.

[0062] In additional nonlimiting embodiments, wear bands may be removed from the tubular without any physical or metallurgical impact to the base tubular. Wear bands may be removed by cutting through the seam welds or through the half shells. After wear bands have been removed, new wear bands may be reinstalled an unlimited number of times without any physical or metallurgical impact to the base tubular. Additionally, multiple wear bands may be applied to the same tubular in order to further increase the number of points of contact with the borehole and increase the potential benefits described above. When multiple wear bands are installed on the same tubular, they may be spaced at any desired interval which may be dependent on the desired rigidity of the tubular, space out for well control equipment or standoff of the tubular relative to the borehole.

[0063] In additional nonlimiting embodiments, wear bands may be mounted to the tubular in an outdoor environment such as on an active work location or tubular rack location. This may be beneficial to prevent extra transportation of the tubulars such as drill pipe from the active work location to a shop setting to allow for the wear bands to be mounted. In some embodiments, wear bands may be mounted to the tubular in a shop or mill type setting, such as for casing which is typically manufactured at a mill and subsequently ran into the borehole without being retrieved.

[0064] In additional nonlimiting embodiments, wear bands may be mounted to the tubular through an automated process. This automated process may allow for the tubular to be moved directly off of pipe racks, either on an active location, pipe yard, mill or shop, and placed back on such pipe racks after the wear band mounting process is completed. The tubular may be fed lengthwise into the equipment used to clamp and weld half shells to the tubular, this method allows for the tubular to be placed back on the same pipe racks it was removed from and may limit the space required for the mounting process. Alternatively, the tubular may be fed sideways into the equipment used to clamp and weld half shells to the tubular. The equipment used to clamp and weld half shells to the tubular may be mobile and in- use may traverse the length of a pipe rack. Such equipment may use wheels or tracks to provide the ability to move to location and / or along the pipe racks. Alternatively, the equipment may be stationary when placed beside the pipe racks, and the tubulars are rolled along the pipe racks to the desired location for use by the equipment. The equipment may include an integral belt sander, wire brush, sandblaster or laser ablation tool to clean the tubular where the wear band is to be mounted.

[0065] In additional nonlimiting embodiments, the equipment may comprise a hydraulic ram assembly for clamping the half shells, in which the hydraulic ram assembly may include Yokes for applying a distributed clamping force to the half shell. The Yokes may comprise a large and stiff backing member in order to provide such even distribution of clamping force. A distributed clamping force compresses the tubular within 10% to 100% of its elastic limit during clamping. A distributed clamping force is applied by four or more contact points (or areas or lines of contact) between the lining members and the half shells. A distributed clamping force avoids excessive forces from an opposing set of contact points which would result in oval deformation of the tubular. A distributed force compresses the tubular body with at least 3 or more approximately equal and opposing forces. A distributed force may be applied at two or more axial positions along a half shell during clamping. A distributed force during clamping may be applied at both ends of a half shell, which do not have preinstalled hard banding. A lining member may be provided between the backing member and the half shell, such as a wedge, which may be concave on one side where it contacts the tubular, and flat on the other side where it contacts an angled portion of the backing member. Such wedge may comprise a hard strong material such as steel. Said lining member may comprise a pivoting j aw, such as a j aw of a fractal vice. The pivoting j aw may comprise two discrete surfaces for contacting a half shell, in which the angle between contact surfaces is between 5 and 60 degrees, and in which another side of the pivoting j aw comprises a cylindrical prism for contacting a mating surface of the backing member. The pivoting jaw may comprise a retention feature (such as a dovetail, a bolt, etc.) which travels within a slot of the backing member and functions to maintain the position of the pivoting jaw within the backing member when the clamp is in an open position. The hydraulic ram assembly may comprise a plurality of pivoting jaws, such as four or eight pivoting jaws, allowing for even force distribution to the half shells of differing outer diameters. A pivoting backing member may be disposed between each pivoting jaw and the backing member, and a pivoting backing member may connect two pivoting jaws to a backing member. The lining member may comprise a compliant material, such as rubber, high durometer rubber, urethane or other polymer. A pocket may be formed in a backing member, or in the backside of a competent lining member for a compliant lining member to reside. The pocket may be desirable to prevent the compliant lining member from extruding to the sides when compressed. The compliant lining member may reside between the backing member and the competent lining member. The compliant lining member may be disposed on the inner surfaceof a partial-tubular-shaped competent lining member. The compliant lining member may reside within a pocket of a partial-tubular-shaped competent lining member. The competent lining member may be partial-tubular-shaped and disposed between the pivoting jaw and the half shell. A flexible shield member such as copper, tungsten or other similar refractory material may connect between the partial-tubular-shaped competent lining member and the backing member and prevents weld spatter and other foreign material from contaminating the contact surfaces of the pivoting jaw. The clamping equipment may comprise surfaces for contacting a half shell of various internal diameters to accommodate preinstalled features of a half shell. The clamping equipment may comprise inner surfaces with complex geometry for contacting a half shell with a complex geometry of pre-installed features, such as stabilizer blades, or injection molded polymer.

[0066] In additional nonlimiting embodiments, the equipment used to clamp and weld half shells to the tubular may include tungsten, copper, or other refractory metal end plates to confine the weld puddle to match the longitudinal-end face of the half shells, and to prevent weld spatter from accumulating on the yokes; these shields may be manually or automatically placed and removed, or they may be fixed to the yokes in a manner that is easily removed.

[0067] In additional nonlimiting embodiments, during the mounting process, forced internal cooling, such as through the use of water or air injection may be used during both the longitudinal welding operation and / or during the hard banding process to prevent heat damage to the tubular’s internal coating. It may be preferable to target the area underneath the weld with cooling through use of wands or other internal instruments which may reach inside the tubular. Alternatively, a gap may be placed between the band and the tubular to heat transfer and prevent heat damage to an internal coating of the tubular during the weld overlay process. One of the benefits of using mild steel half shells is that a short, or negligible cool down time is required between performing the longitudinal weld on the half shells and the weld overlay.

[0068] In various embodiments, there may be included any one or more of the following features: The wear band comprising low carbon steel. The wear band is installed and welded without pre-heating of the half shells. The one or more arcuate shell portions comprise a pair of half cylindrical shell portions that are longitudinally welded together. Each half cylindrical shell portion, prior to installation on the tubular, has an arc length of an inside surface being equal to or less than one-half of an outer circumference of the tubular body at a wear band installation location along the tubular body. Each half cylindrical shell portion, prior to installation on the tubular, has an inside radius equal to or larger than an outside radius of the tubular body at the installation location. An inner radius of the one or more arcuate shell portions is equal to or smaller than an outer radius of the downhole tubular. The wear band is installed without fillers or adhesives between the wear band and the tubular. The one or more arcuate shell portions are longitudinally welded together along a longitudinal seam that divides longitudinal edges of the one or more arcuate shell portions, to form a longitudinal weld. A backing strip underlying the longitudinal weld between the tubular body and the hollow cylindrical shell. A backing strip is located between the tubular and a longitudinal weld. The backing strip comprises a highly thermal conductive and / or thermally resistant material to allow for heat dissipation such as tungsten, tungsten carbide, tungsten alloy, molybdenum, silver, copper, aluminum nitride, silicon carbide, graphite or ceramic. The backing strip comprises tungsten or a tungsten alloy. The longitudinal edges of the backing strips are beveled to reduce the interstitial space. The half shells have a uniform radius on the inner surface without a step cut into them for the backing strip. The backing strip hasa thickness profile matching a non-uniform thickness profile of a gap formed between the half shells and the tubular. The backing strip has a width greater than a width of a root gap width of the longitudinal seam, with both widths defined in a circumferential direction in cross-section of the tubular body. The backing strip has a width greater than the root gap of the longitudinal weld. The backing strip has a thickness between 0.05mm and 5mm. The backing strip has a width between 2mm and the full circumference of the tubular. A cap pass of the longitudinal weld comprises a hard facing alloy with a relatively higher hardness compared to a root pass of the longitudinal weld. The number of half shells is two. Each half shell is manufactured with an inside surface circumference being approximately equal to or slightly less than one-half of the tubular outer circumference at the intended installation location. A longitudinal length of the one or more arcuate shell portions is equal to or greater than an outside diameter of the tubular body up to a maximum of four times the outside diameter of the tubular body. The inside surface circumference of each half shell is between 20mm less to 0.1mm less than one-half of the tubular outer circumference at the installation location. Each half shell is manufactured with an inside surface radius approximately equal to or slightly larger than the outside radius of the tubular at the intended installation location. The inside surface radius of each half shell is between 10mm less to 20mm more than the tubular outer radius at the installation location. The longitudinal edges of each half shell are profiled for welding with a root gap between 0mm and 30mm when the half shells are clamped. The half shells are clamped together on the tubular body, making direct contact between the band and the tubular, with a distributed clamping force sufficient to radially compress the tubular. The clamping force is sufficient to compress the tubular between 10% and 100% of its elastic limit. A sufficiently large initial root gap is present at both of the diametrically opposite V grooves to allow compression of the tubular without interference of the half shells at the root of the V grooves. The method of installing a wear band wherein the clamping force may be empirically determined by testing on samples of the actual tubular and band and welding consumables, such that the additive effects of the clamping force plus the weld shrinkage remains below 100% of the elastic limit for radial compression of the tubular body, Finite Element Analysis (FEA) of clamping forces may be calibrated and used to determine optimal clamping and welding parameters for new sizes, weights, and grades of tubular. The method of installing a wear band wherein longitudinal seam welds are performed while maintaining the radial compressive clamping force. The method of installing a wear band wherein the clamping force is maintained during initial cooling of the longitudinal welds. The method of installing a wear band wherein the clamping force is monitored and adjusted for changes due to weld shrinkage forces during the entire process using load cells or strain gauges. The method of installing a wear band wherein the first weld pass is a root weld, during which, power input and travel speed of root pass are controlled to allow for the weld material to penetrate full depth of the V groove without melting the backing strip. The method of installing a wear band wherein clamping force is sufficient to allow a complete seam weld to be completed on side 1 and partially or fully cooled without the weld shrinkage shifting the half shells and widening the root gap on side 2. The method of installing a wear band wherein accelerated cooling of the longitudinal seam welds may be performed using air, water, or other fluids to protect an internal coating of the tubular which may otherwise be degraded by elevated temperatures of the longitudinal seam weld. The wear band with a length greater than or less than 200mm, depending on the service, slip force and clamping force requirements. A greater length increases the achievable slip force of the band with the same clamping force input. The half shell length is between 1 inch and 100 inches. The half shell length is at a minimum of a length equal to the outside diameter of the tubular and of a maximum length equalto 4 outside diameters of the tubular. A thickness greater than or less than 9mm depending on the tubular outer diameter, tool joint outer diameter and borehole inner diameter. The thickness of the wear band is less than the difference between the borehole inner radius and the outer radius of the tubular. The thickness of the wear band is less than the difference between the tool joint outer radius and the outer radius of the tubular. A weld overlay hard banding is applied to the outside diameter of the wear band after it is installed on the tubular. A plurality of weld overlay hard banding on the outer surface. The one or more overlay hard bandings are pre-welded to the one or more arcuate shell portions prior to the wear band being clamped around the tubular body. The weld overlay hard banding is applied to the one or more arcuate shell portions prior to clamping and longitudinally welding. The weld overlay hard banding comprises circumferential rings, helical, longitudinal strips, other patterns or a combination thereof. The weld overlay hard banding is applied to increase resistance to wear of the wear band. The weld overlay hard banding has a lower coefficient of friction than the tubular. An outer surface of the wear band, such as a non-metallic or other coating, has a lower coefficient of friction than the tubular. The weld overlay hard banding comprises a single material, alloy, or composite, or comprises multiple dissimilar weld materials to achieve multiple objectives such as increasing resistance to wear and reducing the coefficient of friction. A half shell with a length greater than 200mm is used to allow the application more than one different weld overlay hard banding materials or external coatings to the band after it is mounted on the tubular. Gaps are left between adjacent weld overlay hard banding rings, which may be beneficial for applying the weld overlay hard banding after the wear band is mounted on the tubular, in order to reduce the heat effect on the tubular and tubular internal coating from the weld overlay hard banding process. Longitudinally welding is commenced while the one or more arcuate shell portions are at ambient temperature in a non-pre-heated state. Roughening a wear band installation location of an outer surface of the tubular body prior to mounting the wear band on the tubular body. Half shells are manufactured with assorted internal diameters and / or assorted internal circumferences to accommodate variations in tubular outer diameter when installed on used tubulars. The tubular outer diameters range from 1 inch to 20 inches. Half shell internal diameter increments or internal circumference increments are between 0.1mm to 10mm. Half shell outer diameter ranges from 0.1 inch to 10 inches larger than the outer diameter of the tubular. The internal diameter of the half shells is precoated with a hard or abrasive coating to increase the friction coefficient between the band and the tubular. Inside surfaces of the one or more arcuate shell portions are pre-coated with one or more of: a soft metal relative to the one or more arcuate shell portions; or a filler substance; to reduce or avoid corrosion between the wear band and the tubular body. The internal diameter of the half shells is precoated with a soft metal such as phosphating or galvanizing, or with a fdler substance such as thread compound, to avoid corrosion between the wear band and the tubular. Sandblasting, belt sanding, or other similar methods are used to clean and / or roughen the tubular outer surface prior to mounting the band on the tubular. Half shells have pre-installed features on the outer diameter prior to mounting to the tubular. The pre-installed features include weld overlays for increased wear resistance or for reduced friction factor, or other surface coatings. The preinstalled features include mechanically retained elements which are inserted from the ID, or molded in place. The cap pass of the longitudinal welds comprises a hard facing alloy. The longitudinal cap pass of wear resistant material is shorter than the wear band, and is only applied over a portion of the length of the seam weld. Slots or grooves are defined through the hollow cylindrical shell of the wear band to the tubular body. Slots allow free movement of fluid between portions of the band and the tubular, these slots may be formed either by grooves in the half shells or by separate spacercomponents located between the half shells and tubular. Filler material, such as thread compound is applied to the outer surface of the tubular prior to wear band installation to prevent fluid invasion of the small interstitial space. Seals are at one or both of opposed ends of the wear band between the wear band and the tubular body. Teflon or rubber seals are placed at either end of the band between the band and the tubular prior to clamping prevent fluid invasion of the small interstitial space. Galvanic corrosion of the tubular in the interstitial space between the band and the tubular is mitigated through use of a low alloy grade for the half shells which provide cathodic protection to the tubular. Inner surfaces of the one or more arcuate shell portions are textured, contoured, indented, scalloped, slotted, grooved, or structured to provide standoff, to reduce heat transfer between wear band and the tubular body. The tubular may comprise drill pipe, casing strings, tubing strings, downhole drilling tools, or rods for downhole pumps. The band may provide a smooth circumferential outer diameter. The band provides has no flow or bypass areas in order to provide sealing capabilities when ran through a blowout preventer annular element or managed pressure drilling rotating head. The band comprises a bladed outer surface, the blades may be straight or spiral. The wear band is structured to provide standoff between the tubular body and a borehole. The wear band is used to provide borehole contact points part way along drilling, measurement-while-drilling or logging-while-drilling components in order to reduce vibration or undesirable bending dynamics of a drilling assembly. The band provides standoff between the tubular and the borehole to assist in borehole cleaning at inclinations greater than 15 degrees. The band provides standoff between the tubular and the borehole which may assist in reducing tubular surface area in contact with the borehole and the potential for differential sticking. The wear band stabilizes the tubular string to reduce buckling and / or vibration. The band allows more efficient weight transfer from surface to the bottom of the tubular string due to increased rigidity and reduced buckling of the tubular string. The band improves the condition of the borehole by providing edges or features to wipe the borehole as the tubular string is rotated or reciprocated. The wear band improves the condition of the filter cake on the internal surface of the borehole by providing edges or features to wipe the filter cake as the tubular string is rotated or reciprocated. Using a wear band installed on a tubular, to reduce outer diameter wear the tubular by virtue of reduced contact between the tubular and the borehole. Using a wear band installed on a tubular, where in-use the friction between the tubular string and the borehole is reduced due to reduced contact area between the tubular string and the borehole and / or due to the wear band outer surface having a lower coefficient of friction than the tubular outer diameter. The wear band provides standoff between the tubular and the borehole to improve cement placement. The wear band provides standoff between the tubular and the borehole to improve cuttings removal and reduce the cuttings bed height in highly deviated or horizontal wells while drilling or circulating. Slots between blades provide a bypass area to allow free movement of fluid. The band may be removed from the tubular without any physical or metallurgical impact to the base tubular. Bands are reinstalled without any physical or metallurgical impact to the base tubular. After removing the wear band, installing the wear band, or a replacement wear band identical to the wear band, on the same or a different tubular body. The tubular body lacks weld heat damage. Multiple bands are applied to the same tubular. Multiple bands are spaced at any desired interval or directly adjacent to other bands on the tubular. Adjacent placement of wear bands provides increased slip resistance, while providing increased flexibility and reducing the bending stress concentration on the tubular as compared to a single band of the same length. The band is mounted to the tubular in an outdoor environment such as on an active work location or tubular rack location. The wear band is mounted to a new tubular at a shop or mill. The band is mounted using anautomated process. The automated process allows for a tubular to be moved directly off of pipe racks and placed back on such pipe racks after the process is completed. The band is applied on new or used tubulars. The installation process for the wear band uses forced internal cooling, such as through the use of water or air injection during the longitudinal welding operation to prevent heat damage to the tubular’s internal coating. The installation process uses forced internal cooling, such as through the use of water or air injection during the weld overlay operation to prevent heat damage to the tubular’s internal coating. The gap between the band and the tubular reduces heat transfer and prevents heat damage to an internal coating of the tubular during a weld overlay process. Weld overlay is applied a short time after the longitudinal welds are completed, without a cool-down time requirement. Weld overlay is pre-installed on the outer diameter of a half shell prior to mounting to the tubular. The wear band and weld fdler materials comprise non-magnetic steel alloys, to allow for the band to be mounted in proximity to magnetic directional sensors. The pre-installed features comprise polymer to provide a shock absorber to reduce lateral shocks to the tubular which may comprise sensitive downhole electronic components such as steering assemblies or measurement tools. The one or more arcuate shell portions comprise a split sleeve whose longitudinal edges are welded together - the wear band comprises a sleeve with a single longitudinal split, which is opened to allow the wear band to slide over ends of tubulars that do not have large tool joints at the end; this opening may result in elastic and / or plastic deformation of the band prior to and during the clamping and longitudinal welding process. Clamping comprises clamping the one or more arcuate shell portions together on the tubular body, in direct contact with the tubular body, with a clamping force that radially compress the tubular body within an elastic limit of deformation of the tubular body. The clamping force applied during clamping is sufficient to compress the tubular body between 10% and 100% of the elastic limit of deformation. A portion of the compression (deformation) achieved during clamping is permanently retained in the tubular, depending on the ratio of wall thickness and Young’s modulus between the tubular body and the wear band. The tubulars are fed lengthwise into the equipment used to clamp and weld half shells to the tubular. The equipment used to clamp and weld half shells to the tubular is mobile and in-use can traverse the length of a Piperack. The mobile equipment is mounted on wheels or tracks. The equipment used to clamp and weld half shells to the tubular includes an integral belt sander, wire brush, or sandblaster. The equipment used to clamp and weld half shells to the tubular includes tungsten, copper, or other refractory metal end plates to confine the weld puddle to match the longitudinal-end face of the half shells. The one or more arcuate shell portions are structured to define a vee-shaped longitudinal seam, which is defined between longitudinal edges of the one or more arcuate shell portions and is where weld material is deposited during longitudinally welding; in which the vee-shaped longitudinal seam defines an initial root gap that is sufficiently wide to permit compression of the tubular body without interference of the one or more arcuate shell portions at a root of the vee-shaped longitudinal seam. The equipment used to clamp and weld half shells to the tubular includes tungsten, copper, or other refractory metal shields to prevent weld spatter from accumulating on the yokes; these shields may be manually or automatically placed and removed, or they may be fixed to the yokes in a manner that is easily removed. Longitudinally welding is performed during clamping. Clamping is maintained at least while initially cooling a longitudinal weld formed within the longitudinal seam. Accelerating cooling of a longitudinal weld formed within the longitudinal seam, using cooling fluid to protect an internal coating of the tubular body which may otherwise be degraded by elevated temperatures of longitudinal welding. The equipment comprises a hydraulic ram assembly for clamping the half shells, wherein the hydraulic ram assembly includes Yokesfor applying a distributed clamping force to a half shell. A Yoke comprises a large and stiff backing member. The Yokes comprise a lining member between the backing member and the half shell. The lining member comprises a wedge. The wedge is concave on one side where it contacts the pipe and flat on another side where it contacts an angled portion of the backing member. The concave part where the lining member contacts the half shell has a radius smaller than the outer radius of the half shell prior to installation such that the contact points, or contact lines, between the lining member and the half shell are towards the edges of the lining member. The wedge comprises a hard strong material such as steel. The yokes each comprise one or more pivoting jaws. There are four or more pivoting jaws. The lining member comprises a pivoting jaw, such as a jaw of a fractal vice. The pivoting jaw comprises two discrete surfaces for contacting a half shell, wherein the angle between contact surfaces is between 5 and 60 degrees, and wherein another side of the pivoting jaw comprises a cylindrical prism for contacting a mating surface of the backing member. The pivoting jaw comprises a retention feature (such as a dovetail, a bolt, etc.) which travels within a slot of the backing member and functions to maintain the position of the pivoting jaw within the backing member when the clamp is in an open position. The clamp comprises a total of four pivoting jaws. The pivoting jaw comprises a total of eight pivoting jaws. A pivoting backing member is disposed between each pivoting jaw and the backing member, and wherein a pivoting backing member connects two pivoting jaws to a backing member. The lining member comprises a compliant material. The compliant lining member resides within a pocket. The pocket is formed in a backing member. The pocket for a compliant lining member is formed in the backside of a competent lining member. The compliant lining member is disposed between the backing member and a competent lining member. A partial-tubular-shaped competent lining member is disposed between the pivoting jaw and the half shell. A flexible shield member connects between the partial-tubular-shaped competent lining member and the backing member and prevents weld spatter and other foreign material from contaminating the contact surfaces of the pivoting jaw. A compliant lining member is disposed on the inner surface of the partial-tubularshaped competent lining member. The compliant lining member resides within a pocket of the partial-tubular-shaped competent lining member. The clamping equipment comprises surfaces for contacting a half shell of various internal diameters to accommodate pre-installed features of a half shell. The clamping equipment comprises surfaces for contacting a half shell at portions of the half shell that does not have hard band material installed. The clamping equipment comprises inner surfaces with complex geometry for contacting a half shell with a complex geometry of preinstalled features. While clamping, rotating the tubular body to orient a longitudinal seam, defined between the longitudinal edges, upward. After making the first longitudinal weld, the claiming force is maintained while the hydraulic ram assembly and the tubular are rotated approximately 180 degrees about the axis of the tubular and the second longitudinal weld is made. Inserting the tubular body as part of a tubing string into a borehole of a well that penetrates a hydrocarbon-bearing formation in the earth. A kit comprising the one or more arcuate shell portions of the downhole wear band system. Clamping the one or more arcuate shell portions around the tubular body to produce the downhole wear band system.

[0069] The foregoing summary is not intended to summarize each potential embodiment or every aspect of the subject matter of the present disclosure. These and other aspects of the device and method are set out in the claims.BRIEF DESCRIPTION OF THE DRAWINGS

[0070] Embodiments will now be described with reference to the figures, in which like reference characters denote like elements, by way of example, and in which: FIG. 1 is a side elevation view of a tubing string with a wear band, supporting a rotary pump disposed on the end of a production tubing string in a wellbore that penetrates an underground formation. FIGS. 1A-1G are side elevation (Figs. 1A-D and IF) and perspective (Fig. IE) views showing various locations on drill pipe where wear bands, as well as an example variation of an extended length wear band, may be installed; FIGS. 2A-2E are perspective (Fig. 2A) and section (Figs. 2B-2E) views showing cross section details of how the half shells of the wear band are welded onto the drill pipe, differentiating two variations of how the tungsten shielding strip is accommodated at the root of the seam weld; FIGS. 3A-3G are perspective (Fig. 3A) and section (3B- 3G) views showing the main variations in the edge preparation on the half shells for the longitudinal seam welds which secure the half shells onto the drill pipe using conventional GMAW, all without causing any metallurgical alteration of the drill pipe, and with Figs. 3B-3G taken along the 3-3 section lines of Fig. 3A; FIGS. 4A-4D are section views showing potential variations in the profdes of the inward facing surface of the half shells in order to reduce heat transfer and thereby mitigate potential damage to typical organic linings inside of the drill pipe which might otherwise occur during the hard surfacing operation; FIG. 5A is a side elevation view showing an alternative manufacturing and installation strategy to simplify field installations and / or reduce the risk of thermal damage to internal organic linings in the drill pipe, wherein the half shells have the weld overlay hard surfacing pre-applied before the half shells are installed on the drill pipe; FIGS. 5B-5G are perspective (Figs. 5B and 5C), side elevation (Figs. 5D and 5F) and section (Figs. 5E and 5G) views showing the use of an alternative strategy to enable potential variations in the purpose and geometry of the end product to satisfy different operational requirements; FIGS. 6A-6C are perspective, side elevation, and section views (taken along the G-G section line of Fig. 6B), respectively showing a nonlimiting embodiment for the apparatus which holds the half shells in place and clamps them with the desired force during the longitudinal seam welding process; FIGS. 7A-7C are section views showing potential variations of the clamping jaws which are intended to equalize the radial force around the circumference of the half shells during the seam welding process; and FIGS. 8A-8F are section views showing mainly subvariants of rigid, non-articulated clamping methods to equalize the radial force around the circumference of the half shells during the seam welding process. The exception is FIG. 8F which shows an alternative articulated jaw design. FIG. 9 is a section view of a split ring sleeve used for a wear band.DETAILED DESCRIPTION

[0071] Immaterial modifications may be made to the embodiments described here without departing from what is covered by the claims.

[0072] The oil and gas industry involves the exploration, extraction, refining, transportation, and marketing of petroleum and natural gas products. The upstream segment, which focuses on exploration and production (E&P), uses advanced technologies such as seismic imaging and horizontal drilling to locate and extract hydrocarbons from deep beneath the earth’s surface. Midstream operations handle the transportation, storage, and wholesale marketing of crude oil, natural gas, and refined products, primarily via pipelines, tankers, and terminals. Downstream activities involve refining crude oil into usable products like gasoline, diesel, and petrochemicals.

[0073] Drilling is a critical operation in the oil and gas industry that enables the extraction of hydrocarbons from subsurface reservoirs. Drilling begins with the exploration phase, where geological and geophysical surveys identify potential drilling locations. Once a site is selected, drilling rigs are deployed to create a wellbore through the earth’s layers to reach oil or gas reservoirs. The drilling process involves the use of a rotating drill bit, powered by surface machinery, to cut through rock formations. Drilling fluid, or "mud," is circulated to cool the bit, remove cuttings, and maintain wellbore stability by balancing formation pressure. Technologies such as directional drilling and horizontal drilling allow operators to reach reservoirs that are not directly beneath the rig or to increase contact with hydrocarbon- bearing formations. Casing and cementing are essential steps to secure the wellbore and prevent contamination of surrounding rock layers, particularly groundwater sources. Modem drilling techniques also utilize measurement-while- drilling (MWD) and logging-while-drilling (LWD) tools to provide real-time data about the well's trajectory and formation properties.

[0074] A tubing string is a crucial component in oil and gas well completion, designed to transport hydrocarbons from the subsurface reservoir to the surface. It may comprise a series of connected steel pipes, typically ranging from 1.5 to 4.5 inches in diameter, that are inserted into the wellbore after drilling is completed. The tubing string is installed inside the production casing and extends from the surface wellhead down to the reservoir. The tubing string provides a controlled pathway for the produced fluids (oil, gas, or water) to flow to the surface, while preventing contamination of the wellbore by isolating the production fluids from the casing. The tubing is secured with couplings and may include additional components such as packers, which seal the annular space between the tubing and casing to prevent fluid migration. Tubing strings are designed to withstand high pressures, corrosive environments, and thermal stresses, making material selection critical. Alloy steel or corrosion-resistant alloys (CRAs) are often used in wells with high concentrations of carbon dioxide or hydrogen sulfide. Additionally, artificial lift systems, such as rod pumps or gas lift valves, may be integrated within the tubing string to enhance production in low-pressure reservoirs. The embodiments of the disclosure may be applied to tubular bodies such as drill pipe, casing string, tubing string, downhole drilling tool, or rod for a downhole pump.

[0075] Referring to Fig. 1, a downhole apparatus may be positioned, for example inserted, within a wellbore 1 in use. The apparatus may comprise a tubing string (production tubing 2), a downhole rotary pump 9, and an intake apparatus 8. The wellbore 1 may be configured to receive fluids through openings between wellbore and reservoir 3 (for example perforations, screens, ports or other lower completions assembly devices). Fluid flowing in wellbore toward a downhole pump 4 may flow past a downhole rotary motor 6 (which may be electric, hydraulic or other). Liquids within the pump 9 have their pressure boosted sufficiently to overcome the hydrostatic head, friction pressure, and surface backpressure and flow up the production tubing 2 to a surface gathering or collection system for further processing and sale. The wellbore 1 may be substantially horizontal, or otherwise highly deviated. One or more wear bands 13 may be located on the tubing 2 as shown to improve the longevity and function of the tubing 2 and the system in general.

[0076] Referring to FIG. 1A, a downhole wear band system is illustrated for use in a downhole drilling application. The system may comprise a wear band 13. The wear band 13 may be located on a tubular body, such as a main pipe body 10, of a downhole tubular 26. The tubular 26 may include tubing connectors, such as tool joints, which are threaded connectors, at opposed ends of the tubular body, such as box end 11A and pin end 1 IB. The figure illustratesa suitable location on a joint of drill pipe where a wear band of the present disclosure 13 may be installed. Referring to Figs. 2A-E, the wear band 13 may be formed of a hollow cylindrical shell 25.

[0077] Referring to Figs. 1A-C, IE, and 2A- E, the wear band 13 may have suitable properties. The shell 25 may be defined in use by one or more arcuate shell portions 15, such as a pair of half cylindrical shell portions (half shells) as shown. Arcuate may refer to a part of a circumference of a cylinder, defined in a cross-section plane perpendicular to an axis of the cylinder. An arc is generally understood to refer to a segment of a curve. that is, whose inner and outer surfaces define circular arcs, without forming a complete circle or cylinder on its own. Plural arcuate portions may be assembled to form the cylinder, in this case the shell 25. Referring to Figs. 1A-1E, the portions 15 may be spaced between the opposed ends 11A, 11B, of the tubular body 10. Positioning the wear band 13 between the connector ends may provide additional strength and advantages over the conventional application to a tool joint. The portions 15 may be clamped around the tubular body 10, for example to elastically deform the tubular body 10. Referring to FIG. IB and IF, the wear bands 13 may have suitable lengths, such as with the elongated variation of the present disclosure wear band 13 illustrated. Referring to FIG. 1C, plural wear bands 13 may be installed on a single joint (tubular) of drill pipe as illustrated, which may be useful in wellbores having tight bending radius which would otherwise cause wear between a single centered wear band and the tool joints at each end. The portions 15 may be in use longitudinally welded together.

[0078] The one or more arcuate shell portions 15 may be longitudinally welded together along a longitudinal seam 30 that divides longitudinal edges 29 of the one or more arcuate shell portions 15, to form a longitudinal weld 16, and to retain an elastic deformation of the tubular body. Compression of the tubular is retained after the distributed clamping force is released, which results in the tubular body having a diameter in all axes which is smaller than the diameter before the wear band is installed (or after the wear band is removed). This elastic compression may result in a diameter change of the tubular in the range of 0.1 to 500 um. A clamping force that is not sufficiently distributed may result in a net compression of the tubular, but in an oval manner, such that the diameter increases in one axis relative to the diameter before the wear band is installed (or after the wear band is removed).

[0079] References to longitudinal, longitudinally, or longitudinality in this document refer to paths that extend from one axial end to the other, for example from axial end 13A to the other axial end 13A of wear band 13. A longitudinal path may be a simple axial line, parallel to a central axis of the tubular body, or may be a complex path, with direction changes. A longitudinal path may have non-zero direction components, for example the path may be oriented at a non-zero angle relative to a line parallel to the central axis, or for example if the longitudinal path is curved, angled, bent, spiraled, or otherwise directed off parallel. In some cases, welds and seams may be primarily longitudinal, with nominal deviations from perfect longitudinality permitted.

[0080] Referring to Figs. 1A-C, IE, and 2A- E, the wear bands 13 may be assembled over a tubular body 26 using suitable methods. The longitudinally welding may be commenced while the one or more arcuate shell portions are at ambient temperature in a non-pre-heated state. Longitudinally welding may be performed during clamping of the one or more arcuate shell portions. Clamping may be maintained at least while initially cooling a longitudinal weld formed within the longitudinal seam. Cooling of a longitudinal weld formed within the longitudinal seam may be accelerated byusing cooling fluid to protect an internal coating of the tubular body which may otherwise be degraded by elevated temperatures of longitudinal welding.

[0081] Referring to Figs. 1A-C, IE, and 2A- E, the shell portions 15 may have suitable dimensions. Each cylindrical shell portion 15, prior to installation on the tubular, has an arc length 15A (Fig. 2B) of an inside surface 15B (Figs. 2B, 2D) being equal to or less than one-half of an outer circumference of the tubular body 10 at a wear band installation location (the location where the wear band 13 is shown installed) along the tubular body. Each cylindrical shell portion 15, prior to installation on the tubular, has an inside radius 15C (Figs. 2B, 2D) equal to or larger than an outside radius 10C of the tubular body 10 at the installation location. The wear band installation location of an outer surface of the tubular body may be roughened prior to mounting the wear band on the tubular body. A longitudinal length 15D of the one or more arcuate shell portions 15 may be equal to or greater than an outside diameter 10D of the tubular body 10, for example up to a maximum of four times the outside diameter 10D of the tubular body. Inside surfaces 15B of the one or more arcuate shell portions 15 may be pre-coated with one or more of a soft metal relative to the one or more arcuate shell portions or a filler substance in order to reduce or avoid corrosion between the wear band 13 and the tubular body 10.

[0082] Referring to Figs. 1A-C, IE, and 2A- E, the wear band 13 may be clamped and welded in place on the tubular body 10. The wear band system may be installed by clamping one or more arcuate shell portions 15 around the tubular body 10, at a location spaced between opposed ends of the tubular body, with a distributed force sufficient to radially compress the tubular body 10 within an elastic limit of deformation of the tubular body 10. The portions 15 may then be longitudinally welded together to form the wear band 13 around the tubular body. Once the wear band 13 has been installed, the tubular body may be inserted as part of a tubing string into a borehole of a well that penetrates a hydrocarbon-bearing formation in the earth, with the wear band functioning to provide standoff between the tubular body and a borehole.

[0083] Referring to Figs. IB, ID, IE, and IF, the wear band 13 may comprise one or more overlay hard bands or hard banding 12, around an outer surface 28 of the hollow cylindrical shell 25. Hard banding is a protective coating process applied to drilling tool joints, primarily drill pipe, to enhance wear resistance and extend their lifespan during drilling operations in the oil and gas industry. Tool joints, which are the thickened ends of drill pipe sections, experience significant friction and abrasion as they rotate and interact with the wellbore, casing, and formation. Hard banding involves applying a layer of wear-resistant material, typically tungsten carbide, titanium, or other hard metal alloys, to the surface of the tool joints through a welding process. The hard banding layer provides a tough, durable shield that reduces metal-to-metal contact, preventing excessive wear of both the drill pipe and the casing. Hard banding also improves resistance to impact and cracking in harsh drilling conditions, such as those encountered in highly abrasive formations. Hard banding is often applied in multiple layers, with modem formulations designed to minimize casing wear while maintaining drill string protection. Referring to FIG. ID, a magnified view of a prior art typical tool joint box end 11A with industry standard hard banding 12 is illustrated. The hard banding 12 shown may comprise three passes about 30mm wide, close packed side by side as far as possible from the internally threaded part of the box end 11A, immediately before the tool joint portion necks down to the diameter of the main pipe body 10.

[0084] Referring to FIG. IE, a detailed isometric view of a typical example of the present disclosure wear band 13 is illustrated. Two arcuate cylindrical portions 15 may be welded together onto the body of the drill pipe 10 by two diametrically opposite longitudinal seam welds 16, which run the full length 15D of the arcuate cylindrical portions 15. Similar to a typical tool joint, there may be multiple close packed passes of weld overlay hard facing (hard banding 17), all running the full circumference of the arcuate cylindrical portions 15 and in some cases overtop of both seam welds 16. The weld overlay hard banding 17 may be applied to an outside surface 15E of the one or more arcuate shell portions 15.

[0085] Referring to FIG. IF, an elongated wear band 13 is illustrated. The extra length allows for a space 18 between the multiple passes of hard banding overlay 17, which reduces the probability of heat damage to internal linings in the drill pipe, without requiring cooling between passes. The extra length proportionately increases the total clamping force on the drill pipe. Additional clamping force may be desired for drilling in especially hard formations with hard and sharp ridges that may catch on a wear band and cause it to slide. Additional length may also be beneficial to allow greater length of hard banding to be used. Additional length may also be beneficial to allow more locations for hard banding to be re-applied to the wear band without having to remove the existing hard banding. The main tradeoff is that the proportionately longer seam welds 19 result in a minor increase of materials cost and installation time.

[0086] Referring to FIG. 2A, the wear band 13 may be structured to facilitate welding and minimize heat transfer to the pipe body 10. A backing strip 22 may underlie the longitudinal weld 16 between the tubular body 10 and the hollow cylindrical shell 25, for example tungsten strip 22. The backing strip 22 may comprise one or more of tungsten, tungsten alloy, tungsten carbide, molybdenum, silver, copper, aluminum nitride, silicon carbide, graphite or ceramic. The backing strip 22 may have a width 22A greater than a width 32A of a root gap 32 width of the longitudinal seam 30, with both widths defined in a circumferential direction in cross-section of the tubular body. An arcuate cylindrical portion 15 may have a shallow longitudinal step 21 on the ID surface 15B to accommodate the important tungsten strip (shown in subsequent figures). Typical arcuate cylindrical portion length 15D for installation on 100mm drill pipe may be 200mm, inside diameter 100mm, and wall thickness 9mm. Each pair of arcuate cylindrical portions 15 may be cut from low carbon steel pipe with Carbon Equivalent (Ceq) < 0.35% having its ID closely matched or slightly larger than the OD of the intended drill pipe. One or both the wear band 13, and a longitudinal weld 16 between the one or more arcuate shell portions, may comprise a non-magnetic steel alloy. A low Ceq enables both the seam welding and the hard facing weld overlay process to be performed without requirements for preheating or restrictions on interpass temperature. This simplifies the welding processes and also makes it possible to prevent thermal damage to corrosion resistant linings which may be present inside of the drill pipe. Referring to FIG. 2B, a transverse cross section after two arcuate cylindrical portions 15 have been secured onto drill pipe 10 with longitudinal seam welds is illustrated.

[0087] Referring to FIG. 2C, the seam weld 16 may comprise a suitable structure after welding. As above, a tungsten strip 22 may fit loosely into step 21. The one or more arcuate shell portions 15 may be structured to define a vee-shaped longitudinal seam 30, which may be defined between longitudinal edges 29 of the one or more arcuate shell portions 15. The seam 30 may be where weld material is deposited during longitudinally welding. The vee-shaped longitudinal seam 30 may define an initial root gap 35. Gap 35 may be sufficiently wide to permit compression of the tubular body 10 without interference of the one or more arcuate shell portions 15 at a root of the vee-shaped longitudinalseam 30. A root weld pass 23 may be used, along with one or more cap weld pass(es) 27. The root weld pass 23 may only fill a bottom third, or less, of a vee groove between the two arcuate cylindrical portions 15 but contacts the tungsten strip. A cap weld pass(es) 27 may fill the remainder of the vee groove (seam 30). To further reduce the risk of thermal damage to any organic or other coatings which are often lining the ID (inner surface 10E) of the drill pipe, the tungsten strips 22 may be augmented with a thin backing of insulating material, for example glass fiber cloth, placed between the tungsten strip 22 and the drill pipe 10. Even though the insulating material may be thin, for example about 0.25mm, it may have a much lower thermal conductivity than tungsten and therefore is effective at reducing the peak temperature of the drill pipe directly under the center of the root pass.

[0088] Referring to FIG. 2D, a transverse cross section after two arcuate cylindrical portions 15 have been secured onto drill pipe 10 with longitudinal seam welds is illustrated, but in this case, there is no step to accommodate the tungsten strip. In this configuration the tungsten strip may have a rectangular or non-rectangular cross section that has tapered longitudinal edges to minimize the size of a crevice between the shell and the pipe where the tungsten strip ends.

[0089] Referring to FIG. 2E, a detailed cross section view of the seam weld in FIG. 2D is disclosed. The step(21 seen in FIG. 2A) is absent in this case and therefore the tungsten strip 22 is tightly clamped onto drill pipe 10 by the two arcuate cylindrical portions 15. This results in a small wedge-shaped crevice 24 adjacent to the tungsten strip which extends about 10mm to 20mm around the curvature of the interface between the drill pipe and the arcuate cylindrical portions. Similar to FIG. 2C, the root weld pass 23 only fills bottom third or less of vee groove between the two arcuate cylindrical portions 15. Cap weld pass 27 fills remainder of vee groove. The cap weld pass 27 of the longitudinal weld may comprise a hard facing alloy, which is relatively harder than root pass of the longitudinal weld.

[0090] Referring to FIG. 3 A, an isometric view of typical wear band, identifying Section 3-3 which explains three variations to the weld preparation of the arcuate cylindrical portions is disclosed. All three of these FIG. 3 series variations show the step 21 feature, but all three of these weld prep cases may be used without the step feature. The tungsten strip is used in all cases because it is the key to preventing any metallurgical alteration of the drill pipe. Tungsten has the highest melting temperature of any metallic element and also has a very high thermal conductivity. These two characteristics make it possible for a very thin layer of tungsten placed at the root of the assembly to prevent the root pass arc from burning through to the underlying drill pipe. Extensive tests have confirmed that tungsten with a thickness of 0.25mm is sufficient to prevent bum through during the root pass weld. Experimentation with thicknesses less than 0.25mm has not been performed since 0.25mm was deemed to be sufficiently thin and challenges may be anticipated handling thinner strips but it is understood that thinner tungsten strips may be viable improvements. It is understood that alternative refractory metal such as molybdenum, tantalum or chromium could be substituted though no other element is expected to perform as well as tungsten. Potentially, copper could be used but as with the alternative refractory metals, a greater thickness would be required which reduces the weld joint mechanical efficiency. If the weld arc were to penetrate through the refractory barrier to the drill pipe, then the integrity of the drill pipe may be compromised, especially in terms of fatigue life since any such penetration would become a potential fracture initiation site. It is well known that high strength, quench hardenable steels commonly used for drill pipe are susceptible to crater cracks from arc strikes. The refractory barrier ensures no disruption of the surface integrity of the drill pipe. Furthermore, the highthermal conductivity of tungsten has been proven to be very effective at preventing thermal degradation of the localized area of the drill pipe surface directly underneath the weld root pass. Localized thermal degradation of the drill pipe microstructure would begin if the surface temperature were to exceed about 500°C. Extensive tests have proven that the root pass is able to melt right down onto, but not through tungsten strip which is only 0.25mm thick, enabling a nearly complete penetration weld joining the two arcuate cylindrical portions. Testing has confirmed that the weld joint mechanical efficiency is reliably over 95%. Testing has also shown that mechanical properties and microstructure of the drill pipe are not degraded. Testing has been completed with a root gap up to 3mm although a root gap of approximately 1.5mm is preferred.

[0091] Referring to FIG. 3B, the first case with a weld prep very commonly used in the pipeline industry is disclosed, further detailed in FIG. 3C.

[0092] Referring to FIG. 3C, a weld prep bevel 31 having an included angle of about 60°, a root gap 32 of about 1.5mm and a root land 33 of about 3mm is disclosed. There is an optimal angle because at one extreme, about 60°, there is much more filler metal deposited with the corresponding large energy input which increases risk of thermal damage to the drill pipe metallurgy and the organic lining. Also, this wide fillet increases the weld shrinkage induced bending moment tangential to the drill pipe OD. FIG. 3C represents this extreme case. At the other extreme, a zerodegree angle reduces the heat input and bending moment to the absolute minimum, however this is the most difficult geometry to weld with much greater risk of weld defects, especially incomplete penetration.

[0093] Referring to FIG. 3D, the second case with a narrower angle weld prep is disclosed, further detailed in FIG. 3E.

[0094] Referring to FIG. 3E, a variation of a weld prep bevel 34 having been reduced to an included angle of about 30° degrees and a root gap 35 of about 1.5mm is disclosed. Also, the root land seen in FIG. 3C has been eliminated. Compared to FIG. 3C, this weld prep reduces bending moment caused by the inevitable weld shrinkage of the cap pass. This variation has one less machining step and has been proven by the authors to be very practical to weld using fully automated GMAW process. The bevel may be produced on both parts equally or in the extreme case, one part may have the entire included bevel angle and the other may have a completely radial face.

[0095] Referring to FIG. 3F, shows the extreme case of narrow gap weld prep, further detailed in FIG. 3G.

[0096] Referring to FIG. 3G, a narrow parallel sided gap 36 in the assembled weld prep with an included angle in the range of 5° and 0°. This variation is the simplest to machine and reduces the shrinkage bending moment to the minimum possible. But it has the tradeoff of being less practical to weld due to poor accessibility in the deep and narrow gap.

[0097] Referring to FIG. 4A, an embodiment is illustrated to mitigate potential heat damage to the drill pipe.An aspect of drill pipe that might experience heat damage includes any coating on the interior (inner surface 10E) of the pipe including corrosion resistant and flow friction reducing organic linings during the hard facing overlay process. It is a very high heat input process to weld on the hard surfacing material, so while the thickness and thermal mass of the arcuate cylindrical portions are sufficient to prevent metallurgical damage to the drill pipe, it still is possible for the hard facing heat to damage organic coatings on the ID surface of the drill pipe. There are many potential coatings which may be present and each has its own unique maximum allowable exposure temperature. The method of installation of thewear band 13 may be carried out in a fashion such that the tubular body 10 lacks weld heat damage. A thin annular space 40, may be defined between the hollow cylindrical shell 25 of the wear band and the tubular body 10. Inner surfaces 15B of the one or more arcuate shell portions 15 may be textured, contoured, indented, scalloped, slotted, grooved, or structured to provide standoff, to reduce heat transfer between wear band 13 and the tubular body 10. Seals 92 may be present at one or both of opposed ends 13A of the wear band 13 between the wear band and the tubular body in order to reduce or eliminate the invasion of corrosive fluids to the small interstitial space formed between a wear band and a tubular body. A method of welding may include accelerating cooling of a longitudinal weld 16 using cooling fluid, for example sprayed (liquid or gas) or otherwise supplied (for example using coolant piping and heat exchangers) to the interior of the drill pipe, to protect an internal coating or other structure of the tubular body 10 which may otherwise be degraded by elevated temperatures of longitudinal welding.

[0098] Referring to FIG. 4B, a thin annular space 40 is underneath where the hard facing / hard banding 17 is to be welded on. The purpose of the space is to eliminate metal to metal conduction which has a high heat transfer coefficient given the high compressive force which otherwise would be present in this zone of the wear band. Testing has proven that the compressive force attaching the wear band 15 to the drill pipe 10 is so strong that removing up to half of the contact area by the presence of the annular space still does not jeopardize the fitness for service in typical wellbore conditions. The inner surfaces 15B of the one or more arcuate shell portions 15 may be structured, for example textured, contoured, indented, scalloped, slotted, grooved, or otherwise, to provide standoff, such as annular space 40, to reduce heat transfer between wear band and the tubular body. The annular space 40 may decrease, reduce or eliminate weld heat damage to the tubular body. Other methods may be used to reduce heat transfer between portions 15 and body 10.

[0099] Referring to FIG. 4C, an intermediate solution to preventing heat damage to organic linings in the drill pipe yet preserving nearly all of the possible clamping force on the drill pipe is disclosed. In the example shown, a scalloped or slotted pattern upon the inner surfaces 15B is used for such effect.

[0100] Referring to FIG. 4D, a simple variation of Fig. 4A is disclosed, where instead of a continuous annular space 40 comprising nearly half of the overall length 15D of the wear band 13, a series of narrow shallow longitudinal, helical or circumferential grooves or combination thereof in a zone 41 are machined into the ID surface 15B of the wear band underneath where the hard banding 17 is to be welded on. In the illustrated version of the profiled zone 41, the grooves and lands are roughly equidimensional but clearly these proportions can be optimized to balance the reduction of thermal conductivity versus the loss of clamping force. For example, by increasing the groove width the heat transfer would be reduced, yet the clamping force in the grooved zone would not be reduced until the clamping stress on the lands approaches the yield strength of the arcuate cylindrical portion material grade.

[0101] Referring to FIGS. 5A-5G, several variants in which the arcuate cylindrical portions are manufactured as complete end products, only requiring simple longitudinal seam welds to attach them to the drill pipe are disclosed.

[0102] Referring to FIG. 5 A, an alternative process sequence in which the hard banding 17 is done on the tube stock before it is split into pairs of arcuate cylindrical portions 15 is disclosed. The one or more overlay hard bands may be pre-welded to the one or more arcuate shell portions prior to the wear band being clamped around the tubular body. In this process the arcuate cylindrical portions 15 may have been pre-manufactured with the hard surfacing so that when installed on the drill pipe, the only welding necessary is the seam welds 16. If desired, a narrow longitudinal capcircumference hard banding in the final product. This enables significant advantages by separating the intensely high heat input process of the typical wide weave hard surfacing from the installation operation on the drill pipe. Hard surfacing requires such a high heat input that it is difficult to prevent damage to organic linings on the ID surface of the drill pipe if performed after the arcuate cylindrical portions are installed on the drill pipe. In various of the methods disclosed, longitudinal welding may be commenced while the one or more arcuate shell portions 15 are at ambient temperature in a non-pre-heated state. Pre-heating is a common approach used with welding, however, it may introduce metallurgical defects and other forms of damage to the tubular body 10. To avoid this, pre-heating may not be used as a technique in the welding stages discussed.

[0103] Referring to FIG. 5B, slots or grooves, such as perforations 51, may be defined through the hollow cylindrical shell 25 of the wear band 13 to the tubular body 10. A variant of the wear band 13 is illustrated in which the modified arcuate cylindrical portions 51 are manufactured with special features, in this case perforations 52 to accommodate low friction polymer 53, premolded into the arcuate cylindrical portions. Alternatively, high hardness metallic buttons such as tungsten carbide (not shown) can be set into the perforations of the arcuate cylindrical portions, again prior to installation on the drill pipe 10. In some cases, inserts, cast non-metallic low friction materials, or other materials are located, for example anchored, in the perforations, slots or grooves.

[0104] Referring to FIG. 5C, the wear band 13 may comprise a bladed outer surface. Half shells (portions15) may be manufactured with bladed or fluted OD features which may improve cuttings transport or reduce the risk of differential sticking. The use of blades is one way that the wear band 13 might be structured to provide standoff between the tubular body and a borehole. In the example shown the wear band 13 is a fluted stabilizer or centralizer type tool variant with four thick, straight flutes 57 is disclosed. To those skilled in the art of drilling tools, many further subvariants of this tool are well understood, for example with helical ribs, or with polycrystalline diamond compact (PDC) inserts set into the ribs, etc. The important common feature is the simple seam weld 16 process with a thin refractory backing strip while the arcuate cylindrical portions are in controlled compression on the drill pipe body which results in a very strongly attached stabilizer or centralizer tool, without risk of degrading the metallurgy or properties of the drill pipe 10.

[0105] Referring to FIG. 5D, the low friction molded polymer variant in which the low heat input of the seam welding process enables the arcuate cylindrical portions to be very strongly attached to the drill pipe without any risk of degrading the drill pipe nor the molded polymer 53 is disclosed.

[0106] Referring to FIG. 5E, the molded polymer variant illustrates internal detail, in particular that the inward facing ends of the perforations are enlarged. This is to create an anchoring geometry which reduces the risk of the polymer pad coming loose from the steel arcuate cylindrical portions.

[0107] Referring to FIG. 5F, the fluted reamer or centralizer variant in which the low heat input of the seam welding process enables the arcuate cylindrical portions to be quickly and very strongly attached to the drill pipe without any risk of degrading the metallurgy or properties of the drill pipe 10 is illustrated.

[0108] Referring to FIG. 5G, section view KK of the fluted reamer or centralizer variant is illustrated showing internal detail, in which the massive steel cross section of the flutes 57 is visible. The thinnest part of the reamer is in the valley 58 between the flutes and typically this feature is required to allow proper flow of drilling fluids past the reamersince the flutes are expected to be in contact with the wellbore. Evident from this section is the advantage of the present disclosure, enabling the secure attachment of reamers with full penetration seam welds 16 along the valley, without degrading the metallurgy or properties of the drill pipe 10.

[0109] Referring to Figs. 6A-8F, various examples are illustrated of devices that can be used to carry out a method of installing a wear band 13 on a tubular body 10. The devices may carry out various stages. A general method of installing a wear band 13 may comprise clamping one or more arcuate shell portions 15 around a tubular body 10. Clamping may be carried out to install the wear band 13 at a location spaced between opposed ends 11A, 11B of the tubular body. Once in place, the method may involve longitudinally welding together the one or more arcuate shell portions 15 to form the wear band 13 around the tubular body 10. Clamping may comprise clamping the one or more arcuate shell portions together on the tubular body, in direct contact with the tubular body, with a clamping force that radially compress the tubular body within an elastic limit of deformation of the tubular body. The clamping force applied during clamping may be sufficient to compress the tubular body between 10% and 100% of the elastic limit of deformation, although other ranges may be used. The wear band 13 may be longitudinally welded during clamping. Clamping forces may be maintained at least while initially cooling a longitudinal weld 16 formed within the longitudinal seam 30.

[0110] Referring to FIG. 6A the prototype apparatus design may be used to prove the effectiveness clamping the arcuate cylindrical portions onto the drill pipe with controllable compression force while the longitudinal seam welds (16 in preceding figures) are executed. The device may have a hydraulic ram 60. The hydraulic ram 60 assembly, may include yokes, such as jaws 61, for applying a uniformly distributed clamping force to the one or more arcuate shell portions 15. The prototype apparatus design consists of two movable upper jaws 61 which slide slightly deeper into the truncated vee-groove of the upper anvil 62 as the compressive clamping force from hydraulic ram 66 pressing the arcuate cylindrical portions onto the drill pipe is increased. These identical elements are mirrored below 63, 64 to react opposite of the downward clamping force. To guide and support the anvils 62, 64 are two identical frame plates 65 sliding on tie rods 68 which transmit the compressive force from the hydraulic ram 66. Endplate 67 completes the force reaction path from the tensile force carried by the four tie rods 68. During the loading and clamping sequence, it is preferable to have the apparatus 60 in a vertical stack as illustrated. During the seam welding operation, it is preferable to rotate it 90° about the pipe axis so that the weld groove is in the flat position (AWS-1G).

[0111] Referring to FIG. 6B, the base case apparatus 60 in the upright position for loading and clamping the drill pipe 10 and arcuate cylindrical portions 15 is illustrated. With counterweights attached below the lower frame plate 65, it is safe and easy to manually rotate the apparatus about the pipe axis 69. This rotation enables both seam welds to be performed in the flat 1G position, consecutively.

[0112] Referring to FIG. 6C, section view GG of the apparatus 60 illustrates the concentric load path starting with the drill pipe 10 in the center, covered by two arcuate cylindrical portions 15, contacted by four jaws 61, 63, driven obliquely inward by the sloped anvils 62, 64, by orthogonal force from opposing frame plates 65, the upper plate being pushed straight downward by hydraulic ram 66.

[0113] Referring to FIG. 7A, a further apparatus simplification with anvils 70 which eliminate the articulated jaws 61, 63 of the base case apparatus 60 is illustrated. FEA modelling shows that this variation of the jaws will providesufficiently uniform clamping force around the arcuate cylindrical portions to avoid permanent distortion of the drill pipe circularity, but only in the case where the curvature of the anvils 70 very closely matches the curvature of the drill pipe 10. In real world operations, this requires a tight tolerance on the OD of the body diameter of the drill pipe, which is possible with new drill pipe, but requires multiple jaw diameters or multiple shell IDs to accommodate worn drill pipe.

[0114] Referring to FIG. 7B, the articulation of the jaws 61, 63 is illustrated. The jaws 61, 63 may have one degree of freedom to slide upward along oblique surfaces of anvil 62 as the clamping force is increased. The included angle between the two opposed planar surfaces is critical for maximizing the uniformity of radial compressive force around the circumference of the drill pipe 10, despite minor variations in the diameter of the drill pipe, as would be the case with used drill pipe.

[0115] Referring to FIG. 7C, the yokes (jaws) may each comprise one or more pivoting jaws 73. A variation of the clamping design, uses pivoting jaws 73 which have one degree of freedom to pivot along curved surface 74 instead of sliding along a sloped plane as in FIG. 7B. There may be a total of four or more pivoting jaws. Each jaw may define a contact point 76, or two or more contact points 76. Similar to FIG. 7B, this degree of freedom maximizes the uniformity of radial compressive force around the circumference of the drill pipe 10, despite minor variations in the diameter of the drill pipe. In contrast to FIG. 7B the contact surfaces between the jaws and the arcuate cylindrical portions is well defined and the jaw face does not closely match the outside diameter of the arcuate cylindrical portions over its entire surface. Defined contact patches or continuous cylindrical contact patches may be used for all jaw configurations.

[0116] Referring to FIG. 8 A, details of the variation in FIG. 7A are illustrated, in which the articulating jaw arrangements of FIG. 7B and FIG. 7C are simplified with rigid anvils 80, each having a cylindrical clamping surface which is coaxial with the drill pipe axis. Replaceable liners 82 of varied thickness provide optimal matching to the actual diameter of the drill pipe as they transmit the clamping force to the arcuate cylindrical portions 15 which generally are of a constant thickness. It is quick and easy to change the liners 82 for different OD drill pipes or if the liners get damaged.

[0117] Referring to FIG. 8B, variation of FIG. 8A is illustrated where a compliant liner 82 is applied to line the inside of the jaw insert 81. The amount of the jaw insert 81 that is lined with the compliant liner 82 may vary with the geometry of the arcuate cylindrical portions 15 and any coatings or other features applied to the exterior of the arcuate cylindrical portions 15. The compliant liner may be an elastomer, thermoset, metal or composite depending on the requirements of the application. The lining member may comprise a wedge. The wedge may be concave on one side where it contacts the tubular body and flat on another side where it contacts an angled portion of a backing member. The yokes may comprise a large and stiff backing member. The yokes may have a lining member between the backing member and the one or more arcuate shell portions 15.

[0118] Referring to FIG. 8C, a variation of FIG. 8A and FIG. 7C is illustrated where the jaw insert 81 is manufactured with a flexible link 83 allowing for small rotation of the clamping surface to match different diameters of drill pipe 10. The flexible link 83 is provides the pivoting action provided by the jaws in FIG. 7C in a more compact form similar to FIG. 8A with less moving components. The flexible link 83 may be integral to the jaw insert 84, or may be attached via mechanical fastening, welding, casting or other means. The flexible link 83 may be made of the same material as the jaw insert 84 or of a different material depending on the application.

[0119] Referring to FIG. 8D, a variation of FIG. 8C is illustrated where the flexible link 83 is replaced by a compliant pad 85 that is applied to the exterior of the jaw insert 86. The jaw may have a reduced section 87 that reduces the force required to flex the jaw insert 86 to emulate the pivoting effect supplied by the flexible link 83 allowing the jaw to provide even clamping pressure over a range of drill pipe 10 diameters.

[0120] Referring to FIG. 8E, the yokes may have a lining member. A variation of FIG. 8B is illustrated where the compliant liner 82 is applied to the jaw insert 81 used to apply clamping pressure to an irregular surface on the outside of the arcuate cylindrical portions 15. The irregular surface in this figure is a polymer pad 88 cast directly onto the arcuate cylindrical portions 15. In other configurations the irregular surface may include but are not limited to hard banding, polymer pads, centralizer vanes and reamers.

[0121] Referring to FIG. 8F, a variation of FIG. 7C is illustrated where the pivoting jaws 73 are used to apply force to a jaw insert 89 that may be lined with a compliant liner 90 to apply uniform clamping force over the half shells 15 and protect the pivoting jaws 73 from damage or contamination. A flexible guard 91 may also be applied in this configuration to prevent contamination from entering the sides of the pivoting jaws 73. This configuration allows for the use of pivoting jaws 73 with irregular half shell outer surfaces such as hard banding, polymer pads, centralizer vanes and reamers.

[0122] Referring to Figs. 6A-8F, the various devices may be structured to rotate while maintaining clamping force. During clamping, the tubular body 10 may be rotated to orient a longitudinal seam 16, defined between the longitudinal edges 29, in an upward facing direction. The clamping force may cause the portions 15 to uniformly encircle the body 10, and compress the body 10 by elastic deformation of same. The ability to re-orient the body 10 while the clamping force is maintained, may permit the body 10 to be oriented more ideally for welding than if welding were carried out while the weld seam 30 were oriented to the side or downwardly, which might otherwise lead to unintended sagging or dripping of weld material. If two or more seams 30 are present for welding, the first seam 30 may be welded in an upright state, and then, after initial cooling of the weld 16, the body 10 may be rotated while maintaining clamping, to orient the subsequent seam 30 upward. Welding of the subsequent seam may then commence. Two, three, or more seams may be welded in such fashion.

[0123] In some cases, the wear band may be structured or installed to be removable and / or reusable. The wear band 13 may be removed by cutting the longitudinal weld 16, or by cutting the portions 15 themselves. If just the weld 16 is cut or otherwise severed, the wear band 13 may then be re-installed on the same or a different tubular body 10. If the wear band 13 was installed with minimal or no heating, the wear band 13 may be able to be removed from the tubular body 10 without creating any physical or metallurgical impact to the tubular body 10.

[0124] Several embodiments have been discussed in the foregoing description. However, the embodiments discussed herein are not intended to be exhaustive or limit the disclosure to any particular form. The terminology which has been used is intended to be in the nature of words of description rather than of limitation. Many modifications and variations are possible in light of the above teachings and the disclosure may be practiced otherwise than as specifically described.SUMMARY OF ALTERNATIVE EMBODIMENTS

[0125] While there are many potential variations in the possible methods and applications of the present disclosure, the primary focus will be on those affording the greatest simplicity, speed, practicality and commercial benefit utilizing any or all of the following strategies:

[0126] Forced cooling of the seam welds after each pass to prevent damage to internal linings.

[0127] Annular space underneath the hard band portion to prevent damage to internal linings.

[0128] Active cooling of the annular space by running a cooling fluid through the space during the hard banding GMAW process.

[0129] Clamshells which are hard surfaced in advance by a variety of processes including but not limited toGMAW or plasma transferred arc welding (PT AW) so that in the case of field installation, all that is required is the seam welds. An additional cap pass may be added using a highly wear resistant GMAW wire sumanyas Duraband NC® to protect the full circumference.

[0130] Likewise, with the apparatus which clamps the arcuate cylindrical portions in readiness for seam welding, there are many potentially beneficial variations on the base case explained in the preceding figures;

[0131] Linkbar design with removable pins to open for loading and unloading.

[0132] ElectroMechanical screw actuator instead of hydraulic ram.

[0133] Tie rod design with retractable and latching tie rods.

[0134] Internal surface coatings to increase friction factor between band and tubular.

[0135] Invasion of corrosive fluids to the very small interstitial space formed between a wear band and a pipe body is not anticipated to be an issue at the present time. Galvanic corrosion in this space may be mitigated by using a low alloy grade for the arcuate cylindrical portions such that cathodic protection is afforded to the pipe body in the interstitial space. Corrosion in the interstitial space may be further mitigated by a variety of means that are compatible with the temperatures reached during installation including: a) spacers or slots to allow free movement of fluid between the wear band and the tubular, b) filler material such as thread compounds typically used in threaded drill pipe or casing connections, c) sacrificial anodes, d) Teflon or rubber seals placed at either end of the wear band to prevent fluid invasion, e) tapering the longitudinal edges of the tungsten strips eliminating the crevice.

[0136] Referring to Fig. 9, in some cases, the one or more arcuate shell portions 15 may comprise a split sleeve whose longitudinal edges 29 are welded together. A split ring or sleeve may be needed to be elastically flexed into an open position to bit fit radially onto the tubular.ADVANTAGES OF VARIOUS EMBODIMENTS OF THE PRESENT DISCLOSURE

[0137] Process is adaptable to work well on both new and worn tubular.

[0138] Equipment system is not expensive - about $200,000 versus well over $1,000,000, both in USD, for just a single friction welder used to install tool joints or integral mid-body upsets.

[0139] Using pre-hard banded arcuate cylindrical portions, the hard banding operation can mostly be completed in a controlled factory setting at lower cost and higher quality than in the field. Only a short straight cap pass of 3” needs to be done in the field on top of each seam weld. The field operation will be greatly simplified. It should alsoenable install of wear bands on internally lined tubular without damaging the lining and without forced cooling during the welding process. A fiberglass-backed tungsten backing strip may further improve the protection of tubular linings.

[0140] Using pre-hard banded arcuate cylindrical portions, it will be an advantage to start and stop each circumferential pass of hard facing at the same angular location and coincide that location with one of the seam welds to cut out the usual irregularities of the hard facing that happen at the start / stop.

[0141] Equipment is compact and lightweight, it may be transported in a pickup truck or mounted to a trailer towable by a pickup truck.

[0142] Equipment is simple enough to be operated by one technician plus helper in the field.

[0143] Equipment may be configured to handle tubular laying on pipe racks. The tubular may be rolled to the equipment location, or the equipment may be on wheels or tracks which allow the equipment to traverse a length of Piperack wherein each joint of tubular only needs to be moved once, lengthwise, into the equipment, and again out of the equipment back into the original location on the racks.

[0144] When hard banding becomes worn, it is possible to add more hard banding to the wear bands, or replace the hard banding on the wear bands.

[0145] When hard banding becomes worn, it is possible for wear bands to be replaced or added to the tubular.It may be simpler and better to install new pre-hard-faced wear bands. They can be beside the old worn wear band or the old one can be cut off and a new one installed in approximately the same location. Wear bands provide a durable, inexpensive, and maintainable component on the tubular. It may be preferable to install multiple wear bands on a tubular for additional protection of the length (i.e. for Range 3 drill pipe joints), or in the event that the first wear band is excessively worn it may be preferable to leave it in place and install another wear band next to it. This may be especially suitable for pre-hard banded arcuate cylindrical portions.

[0146] Arcuate cylindrical portions may have pre-installed features to improve wear resistance. Preinstalled features may include: a) extreme abrasion resistant components such as tungsten carbide buttons inserted from the ID into tapered holes b) wear strips of high abrasion resistant weld overlay in straight longitudinal lines or circumferential rings or helical strips (GMAW or low dilution process of Plasma Transferred Arc Welding PTAW), c) diffusion based surface treatments applied to the exterior of the half shell, d) manufacturing the half shells from abrasion resistant materials, 3) extreme abrasion resistant components such as tungsten carbide inserts pre-installed on the arcuate cylindrical portions utilizing a welding, brazing, or sintering process similar to that used for stabilizers and drill bits.

[0147] The wear band may comprise a bladed outer surface. Half shells may be manufactured with bladed or fluted OD features which may improve cuttings transport or reduce the risk of differential sticking.

[0148] Referring to Figs. 1A-C, IE, and 2A-E, the wear band system may be packaged as a kit for use in a downhole application. The kit may comprise the one or more arcuate shell portions 15. The one or more arcuate shell portions 15 may each have longitudinal edges 29, and that define downhole-tubular-contacting inner surfaces (inner surfaces 15B). The one or more arcuate shell portions 15 may be sized to be assembled, in use in a circumferential fashion to form a wear band 13 around a tubular body 10 of a downhole tubular. The portions 15 may be structured to have an inner radius 15C equal to or smaller than an outer radius of the downhole tubular body 10. The one or more arcuate shell portions 15 may comprise weld overlay hard banding 17, for example pre-welded, on outer surfaces 15E of the one ormore arcuate shell portions 15. The kit may comprise a backing strip 22 structured to underlie, in use, a longitudinal seam 30 defined between longitudinal edges 20 of the one or more arcuate shell portions 15 assembled in use, between the tubular body 10 and the wear band 13.

[0149] Prior commercial products have proposed or used adhesives such as high strength epoxy to attach wear rings. In contrast, this disclosure relies entirely on high force radial compression and friction between steel surfaces. Any softer substance at the interface, such as epoxy, would increase the probability of slippage under high loads, and is likely to fail or become loose under cyclic loading. A filter or gasket material may be added without departing from the spirit of the present disclosure, however a gasket or adhesive is not necessary or believed to be beneficial.

[0150] Importantly, this process delivers an end-product which provides a wear resistant outer surface, does not to degrade or permanently deform the tubular, and can guarantee that it will not slip or break apart. Drilling companies are extremely reluctant to use protective bands, collars or sleeves with multiple pieces which might become loose or break off and jam the tubular in the wellbore. Each tubular stuck pipe occurrence will typically cost several million dollars. Similarly, hard banding applied directly to the drill pipe tube which compromises the drill pipe’s integrity after single or multiple applications is typically avoided due to the high cost of drill pipe failure, although drill pipe failure is typically less costly than drill pipe becoming stuck.

[0151] Where the phrase half shell is used, it should be understood that the feature may apply generally to an arcuate shell portion, unless context dictates otherwise.

[0152] In the claims, the word “comprising” is used in its inclusive sense and does not exclude other elements being present. The indefinite articles “a” and “an” before a claim feature do not exclude more than one of the feature being present. Each one of the individual features described here may be used in one or more embodiments and is not, by virtue only of being described here, to be construed as essential to all embodiments as defined by the claims.

Claims

CLAIMSTHE EMBODIMENTS OF THE INVENTION IN WHICH AN EXCLUSIVE PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:

1. A downhole wear band system for use in a downhole application, the downhole wear band system comprising: a downhole tubular formed of a tubular body with tubing connectors at opposed ends of the tubular body; and a wear band formed by a hollow cylindrical shell that is defined by one or more arcuate shell portions that are: spaced between the opposed ends of the tubular body and clamped around the tubular body to elastically deform the tubular body; and longitudinally welded together to retain an elastic deformation of the tubular body.

2. The downhole wear band system of claim 1 in which the one or more arcuate shell portions comprise a pair of half cylindrical shell portions that are longitudinally welded together.

3. The downhole wear band system of claim 2, in which, one or more of: each half cylindrical shell portion, prior to installation on the tubular, has an arc length of an inside surface being equal to or less than one-half of an outer circumference of the tubular body at a wear band installation location along the tubular body; and each half cylindrical shell portion, prior to installation on the tubular, has an inside radius equal to or larger than an outside radius of the tubular body at the installation location.

4. The downhole wear band system of claim 1 in which the one or more arcuate shell portions comprise a split sleeve whose longitudinal edges are welded together.

5. The downhole wear band system of any one of claim 1 - 4, in which: the one or more arcuate shell portions are longitudinally welded together along a longitudinal seam that divides longitudinal edges of the one or more arcuate shell portions, to form a longitudinal weld; and further comprising a backing strip underlying the longitudinal weld between the tubular body and the hollow cylindrical shell.

6. The downhole wear band system of claim 5 in which the backing strip comprises one or more of tungsten, tungsten alloy, tungsten carbide, molybdenum, silver, copper, aluminum nitride, silicon carbide, graphite or ceramic.

7. The downhole wear band system of any one of claim 5 - 6, in which the backing strip has a width greater than a width of a root gap width of the longitudinal seam, with both widths defined in a circumferential direction in crosssection of the tubular body.

8. The downhole wear band system of any one of claim 5 - 7, in which a cap pass of the longitudinal weld comprises a hard facing alloy, which is relatively harder than a root pass of the longitudinal weld.

9. The downhole wear band system of any one of claim 1 - 8 in which a longitudinal length of the one or more arcuate shell portions is equal to or greater than an outside diameter of the tubular body up to a maximum of four times the outside diameter of the tubular body.

10. The downhole wear band system of any one of claim 1 - 9, in which the wear band comprises one or more overlay hard bandings around an outer surface of the hollow cylindrical shell that is clamped around the tubular body.

11. The downhole wear band system of claim 10 in which the one or more overlay hard bandings are prewelded to the one or more arcuate shell portions prior to the wear band being clamped around the tubular body.

12. The downhole wear band system of any one of claim 1 - 11, in which inside surfaces of the one or more arcuate shell portions are pre-coated with one or more of: a soft metal relative to the one or more arcuate shell portions; or a fdler substance; to reduce or avoid corrosion between the wear band and the tubular body.

13. The downhole wear band system of any one of claim 1 - 12 with slots or grooves defined through the hollow cylindrical shell of the wear band to the tubular body.

14. The downhole wear band system of any one of claim 1 - 13 further comprising seals at one or both of opposed ends of the wear band between the wear band and the tubular body.

15. The downhole wear band system of any one of claim 1 - 14 in which inner surfaces of the one or more arcuate shell portions are textured, contoured, indented, scalloped, slotted, grooved, or structured to provide standoff, to reduce heat transfer between wear band and the tubular body.

16. The downhole wear band system of any one of claim 1 - 15 in which the tubular body comprises drill pipe, casing string, tubing string, downhole drilling tool, or rod for a downhole pump.

17. The downhole wear band system of any one of claim 1 - 16 in which the wear band comprises a bladed outer surface.

18. The downhole wear band system of any one of claim 1 - 17, in which the wear band is structured to provide standoff between the tubular body and a borehole.

19. The downhole wear band system of any one of claim 1 - 18, in which one or both the wear band, and a longitudinal weld between the one or more arcuate shell portions, comprise non-magnetic steel alloy.

20. The downhole wear band system of any one of claim 1 - 19 in which the tubular body lacks weld heat damage.

21. The downhole wear band system of any one of claim 1 - 20 wherein an outer surface of the wear band has a lower coefficient of friction than the tubular body.

22. A kit comprising the one or more arcuate shell portions of the downhole wear band system of any one of claim 1 - 21.

23. A method comprising clamping the one or more arcuate shell portions around the tubular body to produce the downhole wear band system of any one of claim 1 - 21.

24. A method comprising:clamping one or more arcuate shell portions around a tubular body, of a downhole tubular, at a location spaced between opposed ends of the tubular body, with a distributed force sufficient to radially compress the tubular body within an elastic limit of deformation of the tubular body; and longitudinally welding together the one or more arcuate shell portions to form a wear band around the tubular body and to retain an elastic deformation of the tubular body.

25. The method of claim 24 in which longitudinally welding is commenced while the one or more arcuate shell portions are at ambient temperature in a non-pre-heated state.

26. The method of any one of claim 24 - 25 further comprising roughening a wear band installation location of an outer surface of the tubular body prior to mounting the wear band on the tubular body.

27. The method of any one of claim 24 - 26 in which clamping comprises clamping the one or more arcuate shell portions together on the tubular body, in direct contact with the tubular body, with a distributed clamping force that radially compress the tubular body within an elastic limit of deformation of the tubular body.

28. The method of claim 27, in which the distributed clamping force applied during clamping is sufficient to compress the tubular body between 10% and 100% of the elastic limit of deformation.

29. The method of any one of claim 24 - 28 in which: the one or more arcuate shell portions are structured to define a vee-shaped longitudinal seam, which is defined between longitudinal edges of the one or more arcuate shell portions and is where weld material is deposited during longitudinally welding; in which the vee-shaped longitudinal seam defines an initial root gap that is sufficiently wide to permit compression of the tubular body without interference of the one or more arcuate shell portions at a root of the vee-shaped longitudinal seam.

30. The method of any one of claim 24 - 29 in which longitudinally welding is performed during clamping.

31. The method of claim 30 in which: a longitudinal seam is defined between longitudinal edges of the one or more arcuate shell portions; and clamping is maintained at least while initially cooling a longitudinal weld formed within the longitudinal seam.

32. The method of any one of claim 24 - 31 in which: a longitudinal seam is defined between longitudinal edges of the one or more arcuate shell portions; and further comprising accelerating cooling of a longitudinal weld formed within the longitudinal seam, using cooling fluid to protect an internal coating of the tubular body which may otherwise be degraded by elevated temperatures of longitudinal welding.

33. The method of any one of claim 24 - 32 further comprising applying a weld overlay hard banding to an outside surface of the one or more arcuate shell portions.

34. The method of claim 33 in which the weld overlay hard banding is applied to the one or more arcuate shell portions prior to clamping and longitudinally welding.

35. The method of any one of claim 23 - 34 further comprising removing the wear band from the tubular body without creating any physical or metallurgical degradation to the tubular body.

36. The method of claim 35 further comprising, after removing, installing the wear band, or a replacement wear band identical to the wear band, on the same or a different tubular body.

37. The method of any one of claim 23 - 36 in which clamping is carried out using a hydraulic ram assembly, which includes yokes for applying a distributed clamping force to the one or more arcuate shell portions.

38. The method of claim 37, in which, one or more of: the yokes comprise a stiff backing member; and the yokes have a lining member between a backing member and the one or more arcuate shell portions; and the lining member is structured to move relative to the stiff backing member.

39. The method of claim 38 in which: the yokes have the lining member; the lining member comprises a wedge; and the wedge is concave on one side where it contacts the tubular body and flat on another side where it contacts an angled portion of the backing member.

40. The method of any one of claim 37 - 39 in which the yokes each comprise one or more pivoting jaws that can pivot relative to a stiff backing member of the yoke.

41. The method of claim 40 in which there are a total of four or more pivoting jaws.

42. The method of any one of claim 24 - 41 further comprising, while clamping, rotating the tubular body to orient a longitudinal seam, defined between the longitudinal edges, upward.

43. The method of any one of claim 24 - 43 further comprising inserting the tubular body as part of a tubing string into a borehole of a well that penetrates a hydrocarbon-bearing formation in the earth.

44. The method of claim 43 in which the wear band is structured to provide standoff between the tubular body and the borehole.

45. A downhole wear band system kit for use in a downhole application, the downhole wear band system comprising: one or more arcuate shell portions that each have longitudinal edges, and that define downhole-tubularcontacting inner surfaces; in which the one or more arcuate shell portions are sized to be assembled, in use in a circumferential fashion to form a wear band around a tubular body of a downhole tubular, such that the one or more arcuate shell portions can thereafter be clamped to the downhole tubular and longitudinally welded together to secure the wear band on the downhole tubular; and in which the one or more arcuate shell portions comprise weld overlay hard banding on outer surfaces of the one or more arcuate shell portions.

46. The downhole wear band system kit of claim 45 further comprising a backing strip structured to underlie, in use, a longitudinal seam defined between longitudinal edges of the one or more arcuate shell portions assembled in use, between the tubular body and the wear band.

47. The downhole wear band system kit of any one of claim 45 - 46 with an inner radius of the one or more arcuate shell portions equal to or larger than an outer radius of the downhole tubular.

Images