Wear resistant tubular member and system and method for producing same

Abstract

A tubular member includes a central axis, a first end, a second end opposite the first end, and a through bore extending axially from the first end to the second end. Further, the tubular member includes a first connector at the first end and a second connector at the second end. Further, the tubular member includes a tubular region that is axially positioned between the first connector and the second connector and is axially spaced apart from the first connector and the second connector. The tubular member further includes a first upset portion positioned axially between the tubular region and the first connector. The first upset portion has an inner transition within the through bore that increases an inner diameter of the through bore when the through bore advances axially from the first upset portion to the tubular region. In addition, the tubular member includes a first wear pad integrally formed on the tubular region. An outer diameter of the tubular member along the first wear pad is greater than an outer diameter along the tubular region.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of U.S. Provisional Patent Application Serial No. 63 / 346,032, filed on May 26, 2022, entitled “Wear Resistant Tubular Members and Systems and Methods for Producing the Same,” the entire contents of which are incorporated herein by reference for all purposes. STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002] not applicable Background Art

[0003] Elongated tubulars are used in many industrial applications, such as oil and gas drilling and production. Specifically, in oil and gas drilling operations, a drill bit is threadedly attached to one end of the tubular and then rotated (e.g., from the surface, down through a mud motor, etc.) to form a borehole in a subterranean formation. As the drill bit advances in the subterranean formation, additional tubulars are attached (e.g., threadedly attached) at the surface, thereby forming a drill string that extends the length of the borehole. Summary of the invention

[0004] Some embodiments disclosed herein relate to tubular members. In one embodiment, the tubular member includes a central axis, a first end, a second end opposite to the first end, and a through hole extending axially from the first end to the second end. In addition, the tubular member includes a first connector located at the first end and a second connector located at the second end. In addition, the tubular member includes a tubular region, the tubular region is axially positioned between the first connector and the second connector, and is axially spaced from the first connector and the second connector. The tubular member also includes a first upset portion axially positioned between the tubular region and the first connector. The first upset portion has an internal transition portion within the through hole, and when the through hole advances axially from the first upset portion to the tubular region, the internal transition portion increases the inner diameter of the through hole. In addition, the tubular member includes a first wear pad integrally formed on the tubular region. The outer diameter of the tubular member along the first wear pad is greater than the outer diameter along the tubular region.

[0005] Some embodiments disclosed herein relate to methods for manufacturing tubular members. In one embodiment, the method for manufacturing a tubular member includes (a): removing material from a radially outer surface of a cylindrical tubular member, wherein the cylindrical tubular member has a central axis. In addition, the method includes (b): forming a wear pad on the radially outer surface of the tubular member due to (a). In addition, the method includes (c): upsetting an axial end of the tubular member to form an internal transition portion, wherein the internal transition portion increases the inner diameter of the cylindrical tubular member as the cylindrical tubular member advances axially from the axial end. The method also includes (d): attaching a connector to the upset axial end.

[0006] Some embodiments disclosed herein relate to a drill rod. In one embodiment, the drill rod comprises a central axis, a female connector and a male connector, the male connector being axially spaced apart from the threaded female connector. In addition, the drill rod comprises a tubular region, the tubular region being axially positioned between the female connector and the male connector, and being axially spaced apart from the female connector and the male connector. In addition, the drill rod comprises a first upset portion between the tubular region and the female connector. In addition, the drill rod comprises a second upset portion between the tubular region and the male connector. The drill rod further comprises a through hole, the through hole extending axially through the female connector, the first upset portion, the tubular region, the second upset portion and the male connector. When the through hole advances axially from the first upset portion into the tubular region, and when the through hole advances axially from the second upset portion into the tubular region, the inner diameter of the through hole increases. In addition, the drill rod comprises a wear pad formed on the tubular region. The drill pipe has an outer diameter along the wear pad that is greater than an outer diameter along the tubular region.

[0007] The embodiments described herein include a combination of features and characteristics that are intended to address various shortcomings associated with certain existing devices, systems, and methods. The foregoing fairly broadly summarizes the features and technical characteristics of the disclosed embodiments so that the following detailed description can be better understood. Those skilled in the art will readily understand the various features and characteristics described above, as well as other features, after reading the following detailed description and referring to the accompanying drawings. It should be understood that the disclosed concepts and specific embodiments can be easily used as the basis for modifying or designing other structures for achieving the same purpose as the disclosed embodiments. It should also be recognized that such equivalent constructions do not depart from the spirit and scope of the principles disclosed herein. BRIEF DESCRIPTION OF THE DRAWINGS

[0008] To describe in detail various exemplary embodiments, reference will now be made to the accompanying drawings, in which:

[0009] Figure 1 is a schematic diagram of a drilling system according to some embodiments;

[0010] Figure 2 According to some embodiments, one or more wear pads are included. Figure 1 A side cross-sectional view of a drill pipe of a drilling system;

[0011] Figure 3 According to some embodiments Figure 2 An enlarged partial side cross-sectional view of one of the wear pads of a drill pipe;

[0012] Figure 4 is a block diagram of a method of manufacturing a tubular member according to some embodiments;

[0013] Figures 5 to 8 According to some embodiments, Figure 4 The method of forming Figure 2 A sequential cross-sectional view of a process of forming a tubular member;

[0014] Fig. 9 According to some embodiments, it may include Figure 2 a side view of a wear pad on a drill pipe; and

[0015] Fig.10 According to some embodiments, it may include Figure 2 Side view of the wear pad on the drill pipe. DETAILED DESCRIPTION

[0016] During borehole drilling operations, a drill bit is mounted at the lower end of a drill string and is rotated by rotating the drill string at the surface, by actuating a downhole motor or turbine, or both. With weight applied to the drill string, the rotating drill bit engages the underground formation and continues to advance to form a borehole along a predetermined path toward a target area. During these drilling operations, the drill string (or portions thereof) may engage the sidewalls of the borehole or other downhole objects, resulting in wear along the outer surface of the drill string (or more particularly, the drill rods that make up the drill string). This engagement may be particularly evident in horizontal drilling operations, where the path of the borehole deviates from the vertical direction. Ultimately, wear along the outer surfaces of the drill rods that make up the drill string may reduce the strength and service life of these components.

[0017] Thus, embodiments disclosed herein include tubular components and methods for producing tubular components that may have longer service life and durability than standard tubular components. In particular, the disclosed embodiments may include a tubular component of a drill string having one or more wear pads for increasing fatigue resistance, wear resistance, and damage tolerance of the tubular component during drilling operations.

[0018] Reference now Figure 1, schematically illustrates an embodiment of a drilling system 10. In this embodiment, the drilling system 10 includes: a drilling rig 20 located above a borehole 11 that penetrates an underground formation 12; a casing 14 that extends from the ground 17 to an upper portion of the borehole 11 along a central axis or longitudinal axis 15; and a drill string 30 that is suspended in the borehole 11 from a derrick 21 of the drilling rig 20. The drill string 30 has a central axis or longitudinal axis 31 that is aligned with the axis 15 of the casing 14 in this embodiment (note: this alignment is not required and can vary), a first end or uphole end 30a coupled to the derrick 21, and a second end or downhole end 30b opposite the end 30a. In addition, the drill string 30 includes a drill bit 40 located at the downhole end 30b, and a plurality of drill pipe joints 50 (or more simply drill pipes 50) extending from the drill bit 40 to the uphole end 30a. The drill rods 50 are connected end to end, and the drill bit 40 is connected to the lower end of the lowermost drill rod 50. A bottom hole assembly (BHA) (not shown) may be disposed in the drill string 30 near the drill bit 40 (e.g., axially between the drill bit 40 and the lowermost drill rod 50).

[0019] In this embodiment, the drill bit 40 is rotated via the rotation of the drill string 30 from the surface. In particular, the drill string 30 is rotated by the rotary table 22, which is engaged with the kelly 23 coupled to the uphole end 30a of the drill string 30. The kelly 23 and the drill string 30 are suspended on a hook 24, which is attached to a moving block (not shown) with a rotating swivel 25, which allows the drill string 30 to rotate relative to the derrick 21. Although the drill bit 40 and the drill string 30 are rotated from the surface in this embodiment, in general, the drill bit (e.g., the drill bit 40) can be rotated with a rotary table or a top drive, rotated by a downhole mud motor provided in the BHA, or rotated by a combination thereof (e.g., by rotating by the rotary table via the drill string and the mud motor, rotating by the top drive and the mud motor, etc.). For example, if necessary, the rotation via the downhole motor can be used to supplement the rotation power of the rotary table 22 and / or to achieve changes in the drilling process. It should therefore be understood that various aspects disclosed herein are applicable to each of these drilling configurations.

[0020] During drilling operations, a mud pump 26 at the surface 17 pumps drilling fluid or mud into the interior of the drill string 30 through ports in the rotary swivel 25. The drilling fluid exits the drill string 30 through ports or nozzles in the end face of the drill bit 40 and circulates back to the surface 17 through the annulus 13 between the drill string 30 and the sidewall of the borehole 11. The drilling fluid is used to lubricate and cool the drill bit 40, carry formation cuttings to the surface 17, and maintain the pressure required to prevent blowouts.

[0021] Reference now Figure 2Each drill rod 50 making up the drill string 30 is an elongated tubular member configured to be threadedly connected to each adjacent drill rod 50 or other component (e.g., drill bit 40, BHA, etc.). Each drill rod 50 includes a central axis or longitudinal axis 55 aligned with the axis 31 of the drill string 30 during operation, a first end or upper end 50a, a second end or lower end 50b opposite the upper end 50a, a radial outer surface 50c extending axially between the ends 50a, 50b, and a radial inner surface 50d defining a through hole 52, which also extends axially between the ends 50a, 50b.

[0022] Threaded connectors are provided at each end 50a, 50b to facilitate threaded connection of the connector 50 within the drill string 30 as previously described. Specifically, a female or box threaded connector 80 (or more simply "box 80") is located at the upper end 50a, while a male or male threaded connector 60 (or more simply "male 60") is located at the lower end 50b. The box 80 includes a plurality of internal threads configured to be threadedly mated and connected to a male connector (e.g., male connector 60) of an axially adjacent drill pipe 50 (e.g., relative to the axis 31), while the male connector 60 includes a plurality of external threads configured to be threadedly mated and connected to a female threaded connector (e.g., box 80) of an axially adjacent drill pipe 50 (e.g., relative to the axis 31).

[0023] Still refer to Figure 2 and Figure 3 , the drill pipe 50 also includes a pair of upsets that each extend axially from one of the threaded connectors 60, 80 to the central tubular region 58 (or more simply referred to as "tubular region 58"). As used herein, the term "upset" generally refers to an increase in the cross-sectional area of ​​the drill pipe 50 relative to the cross-sectional area within the tubular region 58. In particular, the drill pipe 50 includes a first upset or upper upset 54 extending axially between the box connector 80 and the tubular region 58 and a second upset or lower upset 56 extending axially between the pin connector 60 and the tubular region 58. Each upset 54, 56 includes an enlarged cross-sectional area such that the radially outer surface 50c is enlarged radially outward from the axis 55 relative to the region 58 at the upset 54, 56 to form an outer upset 54a, 56a, and the radially inner surface 50d is enlarged radially inward toward the axis 55 relative to the tubular region 58 at the upset 54, 56 to form an inner upset 54b, 56b.

[0024] The outer upset portion 54a includes a transition portion 51 that smoothly reduces the outer diameter OD of the drill rod 50 between the outer upset portion 54a and the tubular region 58. The inner upset portion 54b also includes a transition portion 53 that smoothly increases the inner diameter ID of the drill rod 50 between the inner upset portion 54b and the tubular region 58. Likewise, the outer upset portion 56a includes a transition portion 57 that smoothly reduces the outer diameter OD of the drill rod 50 between the outer upset portion 56a and the tubular region 58. The inner upset portion 56b also includes a transition portion 59 that smoothly increases the inner diameter ID of the drill rod 50 between the inner upset portion 56b and the tubular region 58. Transition portions 51, 53, 57, 59 are frustoconical surfaces extending between a cylindrical surface forming a radially outer surface 50c and a cylindrical surface forming a radially inner surface 50d located within upset portions 54, 56 and tubular region 58 as previously described and as shown in Figure 2 The internal transition portions 53, 59 may be more generally referred to as M iu , where the subscript "iu" stands for "internal upset".

[0025] As described in more detail below, the drill pipe 50 is assembled by forming upsets 54, 56 at the axial ends of the region 58. Thereafter, the threaded connectors 60, 80 are secured to the upsets 56, 54, respectively, by any suitable method (e.g., welding, integral forming, threading, heat shrinking, etc.). In addition, the upsets 54, 56 may be formed on the tubular region 58 by any suitable method while still complying with the principles disclosed herein. For example, in some embodiments, the upsets 54, 56 are formed by heating the axial ends of the tubular region 58 and impacting each heated end along the axis 55, thereby forcing the surfaces 50c, 50d to radially expand in the manner described above (and as shown).

[0026] Each upset portion 54, 56 may have an axial length extending from the threaded connector 80, 60 to the transition portion 51, 57, respectively, along the radial outer surface 50c. In particular, the upper upset portion 54 has an axial length L extending from the threaded connector 80 to the outer transition portion 51 along the outer upset portion 54a. 54 The lower upset portion 56 has an axial length L extending from the threaded connector 60 along the outer upset portion 56a to the outer transition portion 57. 56 In some embodiments, the axial length L of the upset portions 54, 56 may be increased. 54 , L 56 , to improve the fatigue resistance of the tubular member 50. For example, in some embodiments, the axial length L 54 , L 56 It may be larger than 4 inches (in), such as, for example, 6 in or 8 in.

[0027] In some embodiments, in addition to increasing the axial length L 54 , L 56 In addition, or instead of increasing the axial length L 54 , L 56 , the axial length of the threaded connectors 60, 80 may also be increased. For example, the weld neck of each connector 60, 80 (i.e., the portion of the connector 60, 80 that is welded or otherwise connected to the upset 54, 56, as described above) may be lengthened to achieve a similar increase in fatigue resistance of the tubular member 50 as previously described.

[0028] The drill pipe 50 also includes one or more wear pads 100 positioned along the tubular region 58. The wear pads 100 are characterized in that the wall thickness of the drill pipe 50 (e.g., radially between the radially inner surface 50d and the radially outer surface 50c) increases along the tubular region 58 and relative to the entirety of the tubular region 58.

[0029] Brief reference Figure 1 and Figure 2 During the operation of the drill string 30 and the drill bit 40 rotating in the borehole 11, the wear pad 100 on the drill pipe 50 engages with the inner wall of the borehole (e.g., the borehole 11) or other downhole object. However, due to the increased wall thickness associated with the wear pad 100, damage to the drill pipe 50 caused by such engagement can be limited or completely prevented.

[0030] In some embodiments, the drill pipe 50 may include one or more (e.g., multiple) wear pads 100 positioned along the tubular region 58 such that the above-described contact between the inner wall of the borehole 11 (or other downhole object) and the drill pipe 50 occurs on the wear pads 100. Figure 2 In the embodiment of the present invention, there are two wear pads axially spaced apart from each other along the central axis 55 in the central tubular region 58. Regardless of the number of wear pads 100, each wear pad 100 can be axially spaced apart from both the outer transition portions 51, 57 and the inner transition portions 53, 59 and located in the tubular region 58.

[0031] The one or more wear pads 100 may be integrally formed with the tubular region 58. Thus, the wear pads 100 and the tubular region 58 may be formed as a one-piece, unitary body or structure. As described in more detail below, the wear pads 100 may be machined or formed on the tubular member 58 by removing material from the radially outer surface of a cylindrical tubular member (e.g., a blank tube).

[0032] It should also be understood that within the drill string 30, the drill rod 50 (e.g., Figure 2The drill pipe 50 shown may include standard weight drill pipe, rather than so-called heavy-duty drill pipe, which is typically associated with thicker pipe walls intended to increase the weight applied to the drill bit 40 during operation and to provide a transition from the drill collar to the drill pipe. The heavy-duty drill pipe is typically located in a lower portion of the drill string 30 (e.g., near the drill bit and / or at or near an elbow or bend in the wellbore) because the additional weight associated with such heavier drill pipe may cause buckling or other failures if distributed too high along the drill string 30. Therefore, by including the wear pads 100 on the standard weight drill pipe 50, the upper portion or section of the drill string 30 may be better protected from wear or damage during drilling operations in the manner described above. Further details of embodiments of the drill pipe 50 and the wear pads 100 are provided below.

[0033] Reference now Figure 3 Each wear pad 100 includes a first end or uphole end 100a, and a second end or downhole end 100b opposite the uphole end 100a. In addition, each wear pad 100 includes a radially outer cylindrical surface 102 located between the ends 100a, 100b, and a pair of transition surfaces 104, 106 extending from the cylindrical surface 102 to the ends 100a, 100b, respectively. The outer diameter OD of the drill pipe 50 can reach a maximum at the wear pad 100 along the cylindrical surface 102, so that the transition surfaces 104, 106 can smoothly increase the outer diameter OD of the drill pipe 50 from the tubular region 58 to the cylindrical surface 102. Therefore, the shape of the transition surfaces 104, 106 can be a frustoconical shape. The inner diameter ID of the drill pipe 50 can remain constant (or substantially constant within a suitable tolerance) within the tubular region 58 (including along the wear pad 100).

[0034] Reference now Figure 2 and Figure 3 Each wear pad 100 may have a wall thickness T along the cylindrical surface 102 100 , the wall thickness T 100 Greater than the wall thickness T of the tubular region 58 58 . Wall thickness T 100 The wall thickness T may be measured radially along the cylindrical surface 102 relative to the axis 55 between the radially outer surface 50 c and the radially inner surface 50 d. 58 The wall thickness T of the wear pad 100 may be measured radially along the tubular region 58 relative to the axis 55 between the radially outer surface 50c and the radially inner surface 50d. 100 The wall thickness T of the tubular region 58 may be greater than 58 Therefore, in some embodiments, the wall thickness T 100 With wall thickness T 58 The ratio (T 100 / T 58) can be in the range of about 1.3 to about 2. Due to the wall thickness T 100 and T 58 The difference between the cylindrical surface 102 and the cylindrical surface 102 may extend to a radial height H above the radially outer surface 50c within the tubular region 58. 102 , the radial height H 102 The range may be from about 1 / 16 in (0.0625 in) to about 1 / 4 in (0.25 in), and in some embodiments, such as, for example, 1 / 16 in, 1 / 8 in, 3 / 16 in, 1 / 4 in, etc.

[0035] like Figure 3 As shown, each wear pad 100 includes a radius 101 between the upper transition surface 104 and the tubular region 58 and a radius 103 between the transition surface 104 and the cylindrical surface 102. In addition, each wear pad 100 includes a radius 107 between the transition surface 106 and the cylindrical surface 102 and a radius 105 between the transition surface 106 and the tubular region 58. The radii 101, 105 may be concave radii, while the radii 103, 107 may be convex radii. In addition, each wear pad 100 may include a total axial length L extending axially along the axis 55 between the radii 101, 105 and the ends 100a, 100b. 100 The upper transition surface 104 may have an axial length L extending between the radii 101 , 103 104 , and the lower transition surface 106 may have an axial length L extending between the radii 105, 107 106 . Axial length L 104 , L 106 The axial length L may be substantially increased within the tubular member to reduce bending stresses in the tubular region 58 caused by the wear pad 100. For example, in some embodiments, the axial length L 104 , L 106 The axial length L may be greater than 1 in, such as from about 1.5 in to about 3 in. However, in some embodiments, the axial length L 104 , L 106 One or more axial lengths may be greater than 3 in.

[0036] In some embodiments, the axial length L 104 , L 106 The range may be the total axial length L of the corresponding wear-resistant pad 100 100 However, in some embodiments, the axial length L 104 , L 106 It can be lower than the total axial length L of the corresponding wear-resistant pad 100 100 6.25% or higher than 12.5%. Axial length L104 , L 106 Can be the same or different. In some embodiments, the length L 104 , L 106 At least one length of L can be set so that the taper rate or wall thickness change rate along at least one of the transition surfaces 104, 106 can substantially match the taper rate or wall thickness change rate along the inner transition portions 53, 59, respectively. 104 , L 106 As 101, 103, 105, and 107 increase or decrease, the radii 101, 103, 105, and 107 also increase or decrease, respectively.

[0037] As mentioned earlier, in Figure 2 In the illustrated embodiment, there are a total of two axially spaced wear pads 100 within the tubular region 58. Figure 2 In an embodiment, there is a first wear pad or an uphole wear pad 100' and a second wear pad or a downhole wear pad 100". The uphole wear pad 100' is axially spaced between the uphole end 50a of the drill pipe 50 and the downhole wear pad 100", and the downhole wear pad 100" is axially spaced between the uphole wear pad 100' and the downhole end 50b of the drill pipe 50. The uphole end 100a of the uphole wear pad 100' can be axially spaced a distance D1 from the internal transition portion 53 (or more specifically, the downhole end of the internal transition portion 53). In addition, the downhole end 100b of the downhole wear pad 100" can be axially spaced a distance D2 from the internal transition portion 59 (or more specifically, the uphole end of the internal transition portion 59). In some embodiments, the distance D1 and the distance D2 can range from 7.5 feet (ft) to 15 ft. Furthermore, in some embodiments, a single wear pad 100 may be positioned along the tubular region 58, and an uphole end 100a of the wear pad 100 may be spaced apart from the internal transition portion 53 (or more specifically, a downhole end of the internal transition portion 53) by a distance D1, and a downhole end 100b of the wear pad 100 may be spaced apart from the internal transition portion 59 (or more specifically, an uphole end of the internal transition portion 59) by a distance D2.

[0038] Reference now Figure 2 and Figure 3 In some embodiments, the wear pads 100', 100" may have the same axial length (eg, Figure 3 In some embodiments, the wear pads 100', 100" may have the same maximum outer diameter OD (e.g., Figure 3, along cylindrical surface 102), or may have a different maximum outer diameter OD. For example, in some embodiments, the wear pads 100 on the tubular member 50 located at or near the axial middle of the tubular region 58 may have a larger outer diameter OD along cylindrical surface 102 than the wear pads 100 on the tubular members located at or near the threaded connectors 80, 60.

[0039] Reference now Figure 4 , a method 150 of manufacturing a tubular member (such as a drill pipe) having one or more wear pads (eg, wear pad 100) as described herein. The method 150 may be used to produce Figure 2 and Figure 3 Therefore, when describing the features of method 150, reference is also made to Figures 5 to 8 , these figures illustrate features of a method 150 according to some embodiments.

[0040] Initially, at frame 152, the method 150 includes removing material from a radially outer surface of a cylindrical tubular member and, at frame 154, forming one or more wear pads on the radially outer surface of the tubular member while removing material from the radially outer surface. Figure 5 A blank cylindrical tubular member 200 (or more simply "tubular member 200") is shown having a first or upper end 200a and a second or lower end 200b opposite the upper end 200a. As previously described, the tubular member 200 may be manufactured or transformed into a Figure 2 The drill rod 50 shown in FIG. 2 . Thus, the tubular member 200 includes a central axis 55, a radially inner surface 50d and a radially outer surface 50c as described above.

[0041] Figure 6A tool 202 is shown for removing material from the radially outer surface 50c according to frame 152 in the method 150. The tool 202 may include any suitable tool, implement, or collection thereof that may be used to remove metal or other suitable material. For example, in some embodiments, the tool 202 may include a cutting tool, drill, grinder, sander, etc. mounted in a lathe, a computer numerical control (CNC) machine, a milling machine, etc. During operation, the tool 202 may engage with the radially outer surface 50c (during which the tubular member 200 may rotate about the central axis 55) so that a layer or strip of material is removed (or processed) from the radially outer surface 50d. The engagement of the tool 202 with the radially outer surface 50c may be controlled so that, according to frame 154, one or more wear pads 100 are formed on the tubular member 200 when material is removed from the radially outer surface 50c. Specifically, less material may be removed from the radially outer surface 50c at selected locations so that one or more wear pads 100 are integrally formed along the radially outer surface 50c. The wear pad 100 may be the same as described above, and thus the wear pad 100 may include the ends 100a, 100b and surfaces 102, 104, 106 as previously described.

[0042] Reference again Figure 4 The method 150 further includes, at frame 156, upsetting the axial end of the tubular member. Figure 7 , the axial ends 200a, 200b of the tubular member 200 may be upset so that the upper upset portion 54 and the lower upset portion 56 are formed thereon. As previously described, the upper upset portion 54 and the lower upset portion 56 may include outer upset portions 54a, 56a on the radially outer surface 50c and inner upset portions 54b, 56b on the radially inner surface 50d, respectively. In some embodiments, the axial ends 200a, 200b of the tubular member 200 are upset by striking the axial ends 200a, 200b in the axial direction (along the axis 55) with a suitable punch, hammer or other suitable instrument so that the material of the tubular member 200 is moved to form the upper upset portion 54 and the lower upset portion 56. As previously described, the axial ends 200a, 200b may be heated prior to impacting the axial ends 200a, 200b to form the upsets 54, 56, respectively.

[0043] In some embodiments, frame 156 may be performed after frame 152 and frame 154, so that the axial end of the tubular member is upset after forming one or more wear pads on the radial outer surface. Conversely, in some embodiments, frame 156 may be performed before frame 152 and frame 154, so that the axial end of the tubular member is upset before forming one or more wear pads on the radial outer surface.

[0044] Reference again Figure 4The method 150 includes, at frame 158, attaching a threaded connector to the upset axial end of the tubular member. For example, referring now to Figure 8 , the threaded connectors 80, 60 are attached to the upset axial ends 200a, 200b via welding. Attaching the threaded connectors 80, 60 to the axial ends 200a, 200b completes the drill pipe 50 as previously described. Thus, the wear pads 100 are positioned along the tubular portion 58 as previously described.

[0045] Reference now Fig. 9 In some embodiments, one or more annular anti-wear treatments 120 may be included along the cylindrical surface 102 (or a portion thereof) of one or more wear pads 100 to enhance the wear resistance and durability of the corresponding wear pads 100. Generally, the annular anti-wear treatments 120 may be disposed at one or more discrete locations along the cylindrical surface 102, or may be disposed along the entire cylindrical surface 102 (i.e., extending axially from radius 103 to radius 107). Fig. 9 In the illustrated embodiment, two annular anti-wear treatments 120 are provided on the cylindrical surface 102. Each annular anti-wear treatment 120 extends annularly around the entire circumference of the cylindrical surface 102. In this embodiment, one annular anti-wear treatment 120 extends axially from each radius 103, 107. In addition, each annular anti-wear treatment 120 includes a first end or uphole end 120a, a second end or downhole end 120b, and a length L measured in the axial direction from end 120a to end 120b. 120 Typically, the length L of each anti-wear treatment portion 120 is 120 The length L of each anti-wear treatment 120 may vary, be different from one or more other anti-wear treatments 120, be the same as one or more other anti-wear treatments 120, or a combination thereof, depending on the needs and specific applications. For example, in some embodiments, the length L of each anti-wear treatment 120 may be different from one or more other anti-wear treatments 120, be the same as one or more other anti-wear treatments 120, or a combination thereof. 120 The range of L can be from ¾ in to 2.0 in. In an embodiment where a single anti-wear treatment 120 covers the entire cylindrical surface 102, the length L of the anti-wear treatment 120 is 120 The same as the axial length of cylindrical surface 102 (measured axially from radius 103 to radius 107 ).

[0046] In general, each anti-wear treatment 120 can be any coating, layer or treatment known in the art that hardens and enhances the wear resistance of one or more areas of the cylindrical surface 102. Examples of suitable treatments that can be used for any one or more anti-wear treatments 120 include, but are not limited to, hard coatings or hard bandings that include a harder material than the underlying material defining the cylindrical surface 102 (e.g., TCS-Titanium, TCS-800, TCS-XL, or Smooth-X available from Tubuscope, National Oilwell Varco, Inc., Houston, Texas, USA; or other hard metal wear protection applied by various methods such as welding, cladding, etc.); or surface hardening to enhance the hardness of the material defining the cylindrical surface 102 (e.g., heat treatment, thermal hardening, induction or flame hardening, shot peening or laser shot peening, nitriding, cold rolling, etc.). In embodiments where a hardened ring is used for the anti-wear treatment portion 120, the hardened ring can be disposed in a raised or raised annular recess formed in the cylindrical surface 102, such as the annular recess employed in the SmoothEdge® technology provided by Grant Prideco, Inc. of Houston, Texas, USA.

[0047] Reference now Fig.10 In some embodiments, the wear pad 100 of the drill pipe 50 may include one or more grooves 108 extending radially into the cylindrical surface 102. For example, the one or more grooves 108 may extend helically between the transition surfaces 104, 106 around the central axis 55. During operation, the grooves 108 may form flow channels that allow fluid (e.g., drilling fluid) to flow axially through the wear pad 100. Therefore, the inclusion of the grooves 108 may prevent the wear pad 100 from becoming an obstacle to fluid flow within the borehole during drilling operations.

[0048] Embodiments disclosed herein include tubular components and methods for producing the same, which have longer service life and durability than standard tubular components. Specifically, as previously described, the disclosed embodiments may include a tubular component for a drill string having one or more wear pads for increasing fatigue resistance, wear resistance, and damage tolerance of the tubular component during drilling operations.

[0049] The above discussion is directed to various exemplary embodiments. However, those skilled in the art will appreciate that the examples disclosed herein have broad applications, and the discussion of any embodiment is intended only as an example of that embodiment, and is not intended to imply that the scope of the present disclosure (including claims) is limited to that embodiment.

[0050] Certain terms are used throughout the specification and claims to refer to particular features or components. As will be appreciated by those skilled in the art, different people may refer to the same feature or component by different names. This document is not intended to distinguish between components or features that are named differently but have the same function.

[0051] The accompanying drawings are not necessarily drawn to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown for the sake of clarity and conciseness.

[0052] Unless the context dictates otherwise, all ranges listed herein should be interpreted as including their endpoints, and open-ended ranges should be interpreted as including only commercially practical values. Similarly, unless the context dictates otherwise, all lists of values ​​should be interpreted as including intermediate values.

[0053] In the discussion herein and in the claims, the terms "comprises" and "includes" are used in an open manner and should therefore be interpreted as "including but not limited to ...". In addition, the terms "couple" or "connect" are intended to represent an indirect or direct connection. Thus, if a first device is coupled to a second device, the connection may be through a direct connection of the two devices, or through an indirect connection established via other devices, components, nodes, and connectors. In addition, as used herein, the terms "axial" and "axially" generally refer to along or parallel to a given axis (e.g., the central axis of a body or port), while the terms "radial" and "radially" generally refer to perpendicular to the given axis. For example, an axial distance refers to a distance measured along or parallel to an axis, while a radial distance refers to a distance measured perpendicular to the axis. In addition, when the words "about", "usually", "substantially", "approximately", etc. are used herein (including in the claims) and when stated relative to a given value, it means within a range of plus or minus 10% of the given value. Any reference to above or below in the specification and claims is for clarity, where "above," "upper," "upward," "uphole," or "upstream" means toward the surface of the borehole, and "below," "lower," "downward," "downhole," or "downstream" means toward the end of the borehole, regardless of the borehole orientation. As used herein, the terms "approximately," "about," "substantially," and the like mean within 10% (i.e., plus or minus 10%) of the recited value. Thus, for example, a recited angle of "about 80 degrees" means an angle from 72 degrees to 88 degrees, and should be interpreted as including only commercially practical values.

[0054] Although exemplary embodiments have been shown and described, modifications thereof may be made by those skilled in the art without departing from the scope or teachings herein. The embodiments described herein are intended to be exemplary only and not restrictive. Many variations and modifications of the systems, devices, and processes described herein are possible and are within the scope of the present disclosure. Therefore, the scope of protection is not limited to the embodiments described herein, but is only limited by the appended claims, the scope of which shall include all equivalents of the subject matter of the claims. Unless otherwise expressly stated, the steps in a method claim may be performed in any order. Identifiers preceding steps in a method claim (such as (a), (b), (c) or (1), (2), (3)) are not intended to and do not specify a particular order of steps, but are used to simplify subsequent references to such steps.

Claims

1. A tubular member comprising: a central axis, a first end, a second end opposite the first end, and a through hole extending axially from the first end to the second end; a first connector located at the first end; a second connector located at the second end; a tubular region axially positioned between and axially spaced from the first connector and the second connector; a first upset portion axially positioned between the tubular region and the first connector, wherein the first upset portion has an internal transition portion within the throughbore that increases an inner diameter of the throughbore as the throughbore progresses axially from the first upset portion to the tubular region; and A first wear pad is integrally formed on the tubular region, wherein an outer diameter of the tubular member along the first wear pad is greater than an outer diameter along the tubular region.

2. The tubular member according to claim 1, further comprising a second wear pad integrally formed on the tubular region and axially spaced apart from the first wear pad, wherein The outer diameter of the tubular member along the second wear pad is greater than the outer diameter along the tubular region.

3. The tubular member according to claim 2, wherein: The maximum outer diameter of the first wear-resistant pad is different from the maximum outer diameter of the second wear-resistant pad, or the axial length of the first wear-resistant pad is different from the axial length of the second wear-resistant pad.

4. The tubular member according to claim 1, wherein: The first wear pad includes a helical groove extending radially into the first wear pad.

5. The tubular member according to claim 1, wherein: The first wear pad has a radially outer cylindrical surface including an anti-wear treatment.

6. The tubular member according to claim 5, wherein: The anti-wear treatment portion includes a hard coating layer or a hardened ring.

7. The tubular member according to claim 1, wherein: The first wear-resistant pad comprises: First end; a second end, the second end being axially spaced from the first end of the first wear pad; a radially outer cylindrical surface positioned axially between the first end of the first wear pad and the second end of the first wear pad; a first transition surface extending axially from the first end of the first wear pad to the cylindrical surface; and A second transition surface extends axially from the cylindrical surface to the second end of the first wear pad.

8. The tubular member according to claim 7, wherein: The first transition surface and the second transition surface are frustoconical surfaces.

9. The tubular member according to claim 8, wherein: The length of the first transition surface is in a range from about 6.25% to about 12.5% ​​of an axial length between the first end of the first wear pad and the second end of the first wear pad.

10. The tubular member according to claim 1, wherein: The wall thickness of the tubular member along the wear pad is about 1.3 times to about 2 times the wall thickness of the tubular member along the tubular region.

11. A method of manufacturing a tubular member, the method comprising: (a) removing material from a radially outer surface of a cylindrical tubular member, wherein the cylindrical tubular member has a central axis; (b) According to (a), a wear-resistant pad is formed on the radially outer surface of the tubular member; (c) upsetting an axial end of the tubular member to form an internal transition portion that increases the inner diameter of the cylindrical tubular member as the cylindrical tubular member advances axially from the axial end; and (d) Attach a connector to the upset axial end.

12. The method of claim 11, further comprising performing (b) before performing (c).

13. The method of claim 11, further comprising performing (c) before performing (b).

14. The method of claim 11, wherein (a) comprises engaging a tool with the radially outer surface to remove material.

15. The method according to claim 11, wherein: The wear-resistant pad comprises: First end; a second end, the second end being axially spaced from the first end of the first wear pad; a cylindrical surface axially spaced between the first end and the second end; a first transition surface extending axially from the first end to the cylindrical surface; and A second transition surface extends axially from the cylindrical surface to the second end.

16. The method according to claim 15, wherein: The first transition surface and the second transition surface are frustoconical surfaces.

17. The method according to claim 16, wherein: The length of the first transition surface is in a range from about 6.25% to about 12.5% ​​of an axial length between the first end and the second end.

18. The method according to claim 16, wherein: The wall thickness of the tubular member along the wear pad is about 1.3 times to about 2 times the wall thickness of the tubular member along the tubular region.

19. A drill pipe comprising: Central axis; Female connector; a male connector axially spaced from the threaded female connector; a tubular region axially positioned between and axially spaced from the female connector and the male connector; a first upset portion, the first upset portion being located between the tubular region and the female connector; a second upset portion, the second upset portion being located between the tubular region and the male connector; a through hole extending axially through the female connector, the first upset, the tubular region, the second upset, and the male connector, wherein an inner diameter of the through hole increases as the through hole advances axially from the first upset into the tubular region and as the through hole advances axially from the second upset into the tubular region; A wear pad is formed on the tubular region, wherein an outer diameter of the drill pipe along the wear pad is larger than an outer diameter along the tubular region.

20. The drill pipe according to claim 19, wherein The wear-resistant pad comprises: First end; a second end, the second end being axially spaced from the first end; a cylindrical surface axially spaced between the first end and the second end; a first transition surface extending axially from the first end to the cylindrical surface; and A second transition surface extends axially from the cylindrical surface to the second end.

21. The drill pipe according to claim 20, wherein The length of the first transition surface is in a range from about 6.25% to about 12.5% ​​of an axial length between the first end and the second end.

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