EXTENDED WEAR DRILL PIPES AND METHODS OF MAKING AND USING SAME

Description

BACKGROUND INFORMATION

Technical Field

The present disclosure relates to extended wear drill pipes and processes of making and using same, in particular to extended wear drill pipes useful for drilling oil and gas wells, geothermal wells in the geothermal energy field, and other wells.

Background Art

As explained in U.S. Pat. No. 8,783,344, drilling operations subject drill pipe to a variety of stresses, frictional forces, and environments. During directional drilling, the drill pipe will bend, resulting in well bore contact. As a result, the center portion of the drill pipe will wear and ultimately lead to failure or premature replacement of the drill pipe. The terms drill pipe and standard weight drill pipe are referred to interchangeably herein.

Wear pads may be installed at select locations on the drill pipe, which may generally comprise cylindrical, sleeve-like devices installed on the exterior surface of the drill pipe, such as by clamping. To avoid clamping, so-called “integral” wear pads have been developed, which are machined directly into the pipe when making drill pipe or forged as such. However, forging requires many steps, such as heat treatment, cooling, and the like, adding to cost, and sleeves may become partially or totally dislodged from the drill pipe during drilling.

As may be seen, current practice may not be adequate for all circumstances, and at worst may result in premature drill string failure. There remains a need for more safe, robust extended wear drill pipes for oil and gas drilling, geothermal drilling, subsea and other high-temperature operations. The extended wear drill pipes and processes of the present disclosure are directed to these needs.

SUMMARY

In accordance with the present disclosure, extended wear drill pipes and processes of making and using same are described which reduce or overcome many of the faults of previously known extended wear drill pipes and processes.

A first aspect of the disclosure are extended wear drill pipes comprising (or consisting essentially of, or consisting of):

• • a) a tubular drill pipe having a thickness (t1) including a pin upset end having external tapered threads and a box upset end having internal tapered box threads, the tubular drill pipe having an inner bore having a non-threaded inner surface, the inner bore defining a longitudinal axis; and
  • b) the tubular drill pipe having an integral wear pad section having a thickness (t2), where (t2)=(t1)+thickness of a wear pad, the wear pad section positioned approximately midway between the pin upset end and the box upset end, and where (t2) is at least about 50 percent greater than (t1), or at least about 70 percent greater than (t1)

A second aspect of the disclosure are extended wear drill pipes comprising (or consisting essentially of, or consisting of):

• • a) a tubular drill pipe having a thickness (t1) including a pin upset end having external tapered threads and a box upset end having internal tapered box threads, the tubular drill pipe having an inner bore having a non-threaded inner surface, the inner bore defining a longitudinal axis; and
  • b) the tubular drill pipe having an integral wear pad section having a thickness (t2), where (t2)=(t1)+thickness of a wear pad, the wear pad section positioned approximately midway between the pin upset end and the box upset end, the integral wear pad having first and second hardband portions adjacent first and second ends of the integral wear pad.

In certain embodiments the extended wear drill pipe of the present disclosure may have a burst pressure exceeding an anticipated standpipe pressure of a drilling rig. In certain embodiments the extended wear drill pipe of the present disclosure may have an internal pressure capacity equal to or greater than 15,000 psi (about 103,400 kilopascals (kPa)).

In certain embodiments the extended wear drill pipes may have a tensile strength equal to or greater than about 400,000 lbs. (about 190,000 decanewtons (daN)).

In certain embodiments the extended wear drill pipes may have a tortional strength equal to or greater than about 30,000 ft-lbs. (about 41,000 newton-meters (N-m)). In certain embodiments the extended wear drill pipes may have a section modulus equal to or greater than about 3 in³ (about 50,000 mm³), and a polar section modulus equal to or greater than about 6 in³ (about 98,000 mm³). In certain embodiments the extended wear drill pipes may have a cross sectional area body equal to or greater than about 3 in² (about 2,000 mm²), a cross section area OD equal to or greater than about 10 in² (about 6,500 mm²), and a cross sectional area ID equal to or greater than about 6 in² (about 3,900 mm²). In certain embodiments the extended wear drill pipe of the present disclosure may have a coating to mitigate corrosion from the drilling fluid. In certain embodiments the extended wear drill pipe of the present disclosure may comprise a corrosion-resistant material.

In certain embodiments the extended wear drill pipes of the present disclosure may have a grade that exceeds the overpull required at a true vertical depth of 7000 meters. In certain embodiments the extended wear drill pipes may have a grade suitable for high downhole temperatures without degradation. In certain embodiments the extended wear drill pipes may have inner dimensions allowing insertion and withdrawal of coiled tubing through the extended wear drill pipe. In certain embodiments the extended wear drill pipes may comprise a high strength material to minimize outer drill pipe inner diameter.

In certain embodiments the at least one of the external tapered threads of the pin upset end and the internal tapered threads of the box upset end may have thread design known under the trade designation CET®. In certain embodiments the at least one of the external tapered threads of the pin upset end and the internal tapered threads of the box upset end may have thread design known under the trade designation CTX® Examples of thread designs known under the trade designation CET #include, but are not limited to, CET®43, CET®39, CET®54, CET®57 or CET®58. Examples of thread designs known under the trade designation CTX® include, but are not limited to, CTX™39.

In certain embodiments the at least one of the external tapered threads of the pin upset end and the internal tapered threads of the box upset end may have thread design conforming to thread gauge V-0.076 thread form (MOD PAC) design data. Examples of this are the threaded connections known under the trade designations CET®43 (as described in our U.S. Pat. Nos. 10,612,701 and 10,920,913), and CET®45, as described in our co-pending U.S. Patent app. number ______, filed ______ (3657.007).

In certain embodiments the at least one of the external tapered threads of the pin upset end and the internal tapered threads of the box upset end may have thread design conforming to thread gauge V-0.038 thread form design data. Examples of this are the threaded connections known under the trade designation CET®31, CET®38, CET®39, CET®40, CET®46, CET®50, CET®51, CET®54, CET®57, CET®65, and CET®69. The threaded connections known under the trade designation CET®51 is described in detail in our co-pending U.S. Patent app. number ______, filed ______ (3657.008).

In certain embodiments the at least one of the external tapered threads of the pin upset end and the internal tapered threads of the box upset end may have MOD SLH90 thread design Examples of these include the threaded connections known under the trade designations CET®20, CET®21, and CET®24.

In certain embodiments the at least one of the external tapered threads of the pin upset end and the internal tapered threads of the box upset end may have PAC thread design. An example of this includes the threaded connections known under the trade designation CET®22. In certain embodiments the at least one of the external tapered threads of the pin upset end and the internal tapered threads of the box upset end may have H90 thread design. An example of this includes the threaded connections known under the trade designation CET®23.

In certain embodiments, the extended wear drill pipe may have a bore size of 4.75 inches or greater, box and pin outer diameters of 7.25 inches or greater, and upset end outer diameters of 6.00 inches or greater.

A third aspect of the disclosure are methods of making an extended wear drill pipe, one method comprising (or consisting essentially of, or consisting of):

• • a) providing a tubular drill pipe precursor having a thickness (t2), an inner bore having a non-threaded inner surface, the inner bore defining a longitudinal axis,
  • b) selecting a pin upset end having external tapered threads and a box upset end having internal tapered box threads;
  • c) forming an integral wear pad section on the tubular drill pipe precursor by removing material on either side of the central integral wear pad section, forming first and second slip recess sections each having a thickness (t1), the integral wear pad section having thickness (t2), where (t2)=(t1)+thickness of a wear pad, forming a modified tubular drill pipe precursor; and
  • d) welding the pin upset end and the box upset end to opposite ends of the modified tubular drill pipe precursor, forming an extended wear drill pipe, the wear pad section positioned approximately midway between the pin upset end and the box upset end, and where (t2) is at least about 50 percent greater than (t1), or at least about 70 percent greater than (t1)

A fourth aspect of the disclosure are methods of making an extended wear drill pipe, one method comprising (or consisting essentially of, or consisting of):

• • a) providing a tubular drill pipe precursor having a thickness (t2), an inner bore having a non-threaded inner surface, the inner bore defining a longitudinal axis;
  • b) selecting a pin upset end having external tapered threads and a box upset end having internal tapered box threads;
  • c) forming an integral wear pad section on the tubular drill pipe precursor by removing material on either side of the central integral wear pad section, forming first and second slip recess sections each having a thickness (t1), the integral wear pad section having thickness (t2), where (t2)=(t1)+thickness of a wear pad, forming a modified tubular drill pipe precursor;
  • d) securing first and second hardband portions adjacent first and second ends of the integral wear pad; and
  • e) welding the pin upset end and the box upset end to opposite ends of the modified tubular drill pipe precursor, forming an extended wear drill pipe, the wear pad section positioned approximately midway between the pin upset end and the box upset end.

A fifth aspect of this disclosure are drill strings comprising one or more of the extended wear drill pipes of this disclosure. A sixth aspect of this disclosure is a drilling riser incorporating one or more extended wear drill pipes of the present disclosure therein. As used herein “drilling riser” means a standard drilling riser or riser joint, either a low-pressure drilling riser joint or a high-pressure drilling riser joint.

These and other features of the extended wear drill pipes, thread designs, and processes of the present disclosure will become more apparent upon review of the brief description of the drawings, the detailed description, and the claims that follow. It should be understood that wherever the term “comprising” is used herein, other embodiments where the term “comprising” is substituted with “consisting essentially of” are explicitly disclosed herein. It should be further understood that wherever the term “comprising” is used herein, other embodiments where the term “comprising” is substituted with “consisting of” are explicitly disclosed herein. Moreover, the use of negative limitations is specifically contemplated; for example, certain extended wear drill pipes may be devoid of low-strength steels. As another example, an extended wear drill pipe may be devoid of cladding layers, and/or devoid of coatings on inner and/or outer surfaces.

BRIEF DESCRIPTION OF THE DRAWINGS

The manner in which the objectives of this disclosure and other desirable characteristics can be obtained is explained in the following description and attached drawings in which:

FIGS. 1, 3, 10, and 12 are a schematic side-elevation views of four extended wear drill pipes in accordance with the present disclosure;

FIGS. 2, 4, 11, and 13 are a schematic cross-sectional views through a longitudinal center plane of the extended wear drill pipes illustrated schematically in FIGS. 1, 3, 10, and 12, respectively;

FIG. 5 is a table including dimensions and physical properties of one extended wear drill pipe in accordance with the present disclosure;

FIG. 6 is a graph comparing load curves for new tube and the extended wear drill pipe of FIG. 5;

FIG. 7 is a table including data for the load curves presented graphically in FIG. 6;

FIG. 8 is a graph comparing tool joint wear for new tube and the extended wear drill pipe of FIG. 5;

FIG. 9 is a table including data for the tool joint wear presented graphically in FIG. 8; and

FIGS. 14 and 15 are logic diagrams illustrating two methods of making extended wear drill pipes in accordance with the present disclosure.

It is to be noted, however, that the appended drawings of FIGS. 1-4 and 10-13 are not to scale and illustrate only typical extended wear drill pipes and other features of this disclosure. Furthermore, FIGS. 5-9 illustrate data of only one extended wear drill pipe of the present disclosure, and FIGS. 14 and 15 illustrate only two of many possible methods of this disclosure. Therefore, the drawing figures are not to be considered limiting in scope, for the disclosure may admit to other equally effective embodiments. Identical reference numerals are used throughout the several views for like or similar elements.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of the disclosed apparatus, combinations, and processes. However, it will be understood by those skilled in the art that the apparatus and processes disclosed herein may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. All technical articles, published and non-published patent applications, standards, patents, statutes and regulations referenced herein are hereby explicitly incorporated herein by reference, irrespective of the page, paragraph, or section in which they are referenced. All percentages herein are by weight unless otherwise noted. Where a range of values describes a parameter, all sub-ranges, point values and endpoints within that range are explicitly disclosed herein. This document follows the well-established principle that the words “a” and “an” mean “one or more” unless we evince a clear intent to limit “a” or “an” to “one.” For example, when we state “flowing a fluid through a tubing positioned inside a casing of a well”, we mean that the specification supports a legal construction of “a tubing” that encompasses structure distributed among multiple physical structures, and a legal construction of “a well” that encompasses structure distributed among multiple physical structures. As used herein, “API” refers to American Petroleum Institute, Washington, D.C. As used herein, “NACE” refers to the corrosion prevention organization formerly known as the National Association of Corrosion Engineers, now operating under the name NACE International, Houston, Texas. “Psi” refers to pounds per square inch; “ksi” refers to thousand pounds per square inch; “MPa” refers to megapascals; “GPa” refers to gigapascals; “kPa” refers to kilopascals, all of which are units of pressure.

As mentioned herein, known extended wear drill pipes may not be adequate for all circumstances, and at worst may result in premature drill string failure. There remains a need for more safe, robust extended wear drill pipes for oil and gas drilling, geothermal drilling, subsea and other high-temperature operations. The extended wear drill pipes and processes of the present disclosure are directed to these needs.

As further explained herein the extended wear drill pipes of the present disclosure each feature a wear pad section including a wear pad or pads, and in some embodiments hardband sections. The portion of the extended wear drill pipe that has a wear pad section may range from about 5 percent to about 10 percent, or from about 5 to about 8 percent, or from about 6 to about 8 percent of the total pipe length.

As used herein, the labels “first”, “second”, “top”, “bottom, “upper”, “lower”, left”, “right”, “horizontal”, “vertical” are merely convenient terminology to assist the reader, and are examples only, intended to describe the extended wear drill pipes positioned vertically in a well bore. There is for example no reason the “first” and “second” features or the “left” and “right” features could not be reversed.

Referring now to the drawings, FIG. 1 is a schematic side-elevation view, and FIG. 2 is a cross-sectional view through a longitudinal center plane along a longitudinal axis LA illustrating one extended wear drill pipe (EWDP) embodiment 100 in accordance with the present disclosure. The EWDP includes a main body 8 having a thickness t1, a pin upset end shoulder 9, a box upset end shoulder 11, a box upset end 4, a pin upset end 6, and a wear pad section 7 having a thickness t2, where t2=t1+thickness of a wear pad. Embodiment 100 further includes weld areas 13 where the box and pin connections are welded to main body 8.

Pin upset end 6 has external threads 10, in this embodiment the thread form known under the trade designation CET®43, although other thread types may be used. Box upset end 4 has internal threads 5 (FIG. 2), in this embodiment the thread form known under the trade designation CET®43, although other thread forms may be used. The dimensions of thread form CET 43 are fully disclosed in U.S. Pat. No. 10,612,701 and 10, 9. In an embodiment disclosed therein, the connection known under the trade designation CET®43 has an outer diameter of 5.375 inches, an inner diameter of 3 inches, a recommended make-up torque of 24,400 ft-lbs., a tensile yield strength of 805,800 lbs., and a torsional yield strength of 37,500 ft-lbs. A box connection known under the trade designation CET®43 has threads having a pitch of about 0.25″ (4 TPI), an angle of about 60 degrees, a crest to root height of about 0.092500 inch, a taper of about 1.5 in/ft, a crest width of about 0.067 inch, and a root width of about 0.076 inch. A pin connection known under the trade designation CET®43 has threads having a pitch of about 0.25 inch (4 TPI), an angle of about 60 degrees, a crest to root height of about 0.092504 inch, a taper of about 1.5 in/ft, a crest width of about 0.076 inch, and a root width of about 0.067 inch.

FIG. 2 illustrates certain dimensional parameters (diameters, lengths, and thicknesses), while Table 1 lists values for these parameters for four different EWDP embodiments described herein, and Table 2 lists acceptable (broad) and preferred (narrow) ranges for these parameters. Diameters D1 and D2 are, respectively, outside diameter (OD) and inside diameter (ID) of wear pad section 7, while D3 is OD is main body 8 and D4 is OD of box upset end 11, and D9 is OD of pin upset end 9. D5 represents ID of pin end 6 and pin upset end 9, while D6 represents ID of box upset end 11 and D7 and D8 represent OD of weld areas 13, which may be the same or different. Length L1 is length of wear pad section 7, while L2 and L3 represent lengths of box upset end 11 and pin upset end 9, respectively.

FIGS. 11 and 12 illustrate schematically another embodiment 400 that is similar to embodiment 100, except that wear pad section 7 has a length L1 of 20 inches, and the pin and box connections are those known under the trade designation CET 54, which have thread designs conforming to thread gauge V-0.038 thread form design data.

Referring now to FIGS. 3, 4, 10, and 11, FIGS. 3 and 10 are schematic side-elevation views, and FIGS. 4 and 11 are schematic cross-sectional views through a longitudinal center plane along a longitudinal axis LA of FIGS. 3 and 4, respectively, illustrating two extended wear drill pipe (EWDP) embodiments 200 and 300 in accordance with the present disclosure. Embodiments 200 and 300 differ from embodiments 100 and 400 by featuring not only a wear pad section 7, but also hardband sections 16A, 16B as illustrated schematically near the respective first and second ends of the wear pad 7. EWDP embodiments 200 and 300 further have slip recess sections 14. Slip recess sections 14 have smaller OD than the OD of main body 8 in these embodiments 200 and 300. Hardband sections 16A, 16B may be the same or different in terms of length, thickness, and material. In embodiments 200 and 300 they have lengths of 3 inches, thickness of 3/32 inch, and may comprise alloys selected from tungsten carbide, chromium carbide, titanium carbide, and borides. Hardband sections 16A, 16B may have a length ranging from about 1 to about 10 inches, and a thickness ranging from about 1/32 to about 0.5 inch. Slip recess sections 14 may have a length L5 ranging from about 130 to about 60 inches and have an OD that ranges from about 50 percent of D3 to about 90 percent of D3 (the diameter of EWDP main body 8). Angle α (angle between box upset end 11 and weld section 13) may range from about 15 to about 20 degrees; or from about 17 to about 19 degrees; or may be about 18 degrees.

FIG. 5 is a table including dimensions and physical properties of a new standard weight drill pipe, comparing the new tubular to an extended wear drill pipe in accordance with the present disclosure having an OD of 4.175 inches, a main body wall thickness of 0.443 inch, Grade G-105, range of II (31.5 ft.), and pin and box connections known under the trade designation CET 39. FIG. 6 is a graph comparing load curves for new tube and the extended wear drill pipe of FIG. 5. FIG. 7 is a table including data for the load curves presented graphically in FIG. 6. FIG. 8 is a graph comparing tool joint wear for new tube and the extended wear drill pipe of FIG. 5, and FIG. 9 is a table including data for the tool joint wear presented graphically in FIG. 8.

FIG. 14 is a logic diagram illustrating one method embodiment 500 of making an extended wear drill pipe in accordance with the present disclosure (box 502). Embodiment 500 comprises the steps of:

• • a) providing a tubular drill pipe precursor having a thickness (t2), an inner bore having a non-threaded inner surface, the inner bore defining a longitudinal axis (box 504);
  • b) selecting a pin upset end having external tapered threads and a box upset end having internal tapered box threads (box 506);
  • c) forming an integral wear pad section on the tubular drill pipe precursor by removing material on either side of the central integral wear pad section, forming first and second slip recess sections each having a thickness (t1), the integral wear pad section having thickness (t2), where (t2)=(t1)+thickness of a wear pad, forming a modified tubular drill pipe precursor (box 508); and
  • d) welding the pin upset end and the box upset end to opposite ends of the modified tubular drill pipe precursor, forming an extended wear drill pipe, the wear pad section positioned approximately midway between the pin upset end and the box upset end, and where (t2) is at least about 50 percent greater than (t1), or at least about 70 percent greater than (t1) (box 510).

FIG. 15 is a logic diagram illustrating another method embodiment 600 of making an extended wear drill pipe (box 602). Embodiment 600 comprises:

• • a) providing a tubular drill pipe precursor having a thickness (t2), an inner bore having a non-threaded inner surface, the inner bore defining a longitudinal axis (box 604);
  • b) selecting a pin upset end having external tapered threads and a box upset end having internal tapered box threads (box 606);
  • c) forming an integral wear pad section on the tubular drill pipe precursor by removing material on either side of the central integral wear pad section, forming first and second slip recess sections each having a thickness (t1), the integral wear pad section having thickness (t2), where (t2)=(t1)+thickness of a wear pad, forming a modified tubular drill pipe precursor (box 608);
  • d) securing first and second hardband portions adjacent first and second ends of the integral wear pad (box 610); and
  • e) welding the pin upset end and the box upset end to opposite ends of the modified tubular drill pipe precursor, forming an extended wear drill pipe, the wear pad section positioned approximately midway between the pin upset end and the box upset end (box 612).

The extended wear drill pipes of the present disclosure may be used in onshore and subsea drill strings and risers. The pressure of formations in which the extended wear drill pipes may be used may, in some embodiments, be from about 500 psi to about 15,000 psi or greater; alternatively greater than about 700 psi; alternatively greater than about 800 psi; alternatively greater than about 1,000, or greater than about 2,000 psi, or greater than about 3,000 psi. For example, formation pressures may range from about 2,000 to about 5,000 psi; or from about 2,500 to about 4,500 psi; or from about 3,000 to about 4,000; or from about 2,500 to about 5,000 psi; or from about 2,000 to about 4,500 psi; or from about 2,000 to about 3,000 psi; or from about 4,000 to about 5,000 psi; or from about 3,000 to about 10,000 psi; or from about 4,000 to about 8,000 psi; or from about 5,000 to about 15,000 psi, or higher than 15,000 psi. All ranges and sub-ranges (including endpoints) between about 500 psi and about 15,000 psi are considered explicitly disclosed herein. The temperature of formations in which the extended wear drill pipes may be used may, in some embodiments, be below about 750° F., or below about 700° F., or below about 600° F., or below about 500° F., or below about 400° F.

The extended wear drill pipe may be made of metals. Suitable metals include stainless steels, for example, but not limited to, 306, 316, 4145, 4145H, and 4145HT, and the like, as well as titanium alloys, aluminum alloys, and the like. High-strength materials like C-110 and C-125 metallurgies that are NACE qualified may be employed. (As used herein, “NACE” refers to the corrosion prevention organization formerly known as the National Association of Corrosion Engineers, now operating under the name NACE International, Houston, Texas.) Use of high strength steel and other high strength materials may significantly reduce the wall thickness required, reducing weight. Threaded connections may eliminate the need for 3^rd party forgings and expensive welding processes-considerably improving system delivery time and overall cost. It will be understood, however, that the use of 3^rd party forgings and welding is not ruled out for system components described herein and may actually be preferable in certain situations.

Certain components may comprise MONEL, HASTELLOY, titanium, alloy 20, aluminum, or other corrosion-resistant machinable metal. Corrosion-resistant alloys may be preferred in certain sour gas or other service where H2S or acid gases or vapors may be expected, such as T304 stainless steel (or analogs thereof, such as UNS S30400; AMS 5501, 5513, 5560, 5565; ASME SA182, SA194 (8), SA213, SA240; ASTM A167, A182, A193, A194) or T316 stainless steel (or analogs thereof, such as UNS S31600, SS316, 316SS, AISI 316, DIN 1.4401, DIN 1.4408, DIN X5CrNiMo17122, TGL 39672 X5CrNiMo1911, TGL 7143X5CrNiMo1811, ISO 2604-1 F62, ISO 2604-2 TS60, ISO 2604-2 TS61, ISO 2604-4 P60, ISO 2604-4 P61, ISO 4954 X5CrNiMo17122E, ISO 683/13 20, ISO 683/13 20a, ISO 6931 X5CrNiMo17122, JIS SUS 316 stainless steel, or the alloy known under the trade designation MONEL® nickel-copper alloy 400. The composition and some physical properties of the alloy known under the trade designation MONEL® nickel-copper alloy 400 are summarized in various published U.S. patents (for example, U.S. Pat. No. 11,851,970), and in Publication Number SMC-053 Copyright © Special Metals Corporation, 2005. The composition and some physical properties of T304 and T316 stainless steels are also summarized in U.S. Pat. No. 11,851,970. The alloy known under the trade designation MONEL& nickel-copper alloy 400 (equivalent to UNS N04400/W.Nr. 2.4360 and 2.4361) is a solid-solution alloy that can be hardened only by cold working. It has high strength and toughness over a wide temperature range and excellent resistance to many corrosive environments. The skilled artisan, having knowledge of the particular application, pressures, temperatures, and available materials, will be able design the most cost effective, safe, and operable system components for each particular application without undue experimentation.

In certain embodiments the extended wear drill pipes of the present disclosure may have a service trim of HH (API 6A), which is used in highly corrosive and extreme service environments. The main body of the EWDP and pin and box connections in these embodiments may be made from 4130 steel and may have an alloy known under the trade designation 625 Inconel inlay throughout. 4130 steel is a chromium-molybdenum alloy steel and is considered a low carbon steel. It has a density of 7.85 g/cm³ (0.284 lb./in³) and benefits from heat-treatment hardening. It is an exceptional welding steel, being weldable in all commercial methods, and is readily machined in its normalized/tempered condition. 4130 steel is easily cold worked, hot worked, and forged, but cannot be aged. It has excellent ductility when annealed and is a through-hardening alloy. Properties of 4130 steel are publicly available, for example on MatWeb.com. Alloy 625 is a nonmagnetic, corrosion—and oxidation-resistant, nickel-based alloy. Its strength and toughness in the temperature range cryogenic to 2000° F. (1093° C.) are derived from the solid solution effects of the refractory metals, columbium and molybdenum, in a nickel-chromium matrix. The alloy has excellent fatigue strength and stress-corrosion cracking resistance to chloride ions. Properties are publicly available, for example, in the publication “IINCONEL alloy 625”, published by Special Metals Corporation (2013).

As used herein “welding” can be any one or more welding operations known in the art, including gas metal arc welding (GMAW or MIG), gas tungsten arc welding (GTAW of TIG), shielded metal arc welding, flux cored arc welding, electron beam laser welding, thermit welding, submerged arc welding (DAW), plasma arc welding (PAW), gas welding/oxyacetylene welding, electroslag welding (ESW), resistance welding (RSW), stud welding (SW), friction welding (FW), cold welding (CW), atomic hydrogen welding (AHW), and others.

The extended wear drill pipes of the present disclosure may be built to meet ISO standards, Det Norske Veritas (DNV) standards, American Bureau of Standards (ABS) standards, American Petroleum Institute (API) standards, and/or other standards.

What has not been recognized or realized are extended wear drill pipes, couplers, coupling systems, threads designs, and processes for making and using same that are robust and safe. Extended wear drill pipes and processes to accomplish this without significant risk to workers is highly desirable.

From the foregoing detailed description of specific embodiments, it should be apparent that patentable extended wear drill pipes and processes have been described. Although specific embodiments of the disclosure have been described herein in some detail, this has been done solely for the purposes of describing various features and aspects of the extended wear drill pipes and processes and is not intended to be limiting with respect to their scope. It is contemplated that various substitutions, alterations, and/or modifications, including but not limited to those implementation variations which may have been suggested herein, may be made to the described embodiments without departing from the scope of the appended claims. Some extended wear drill pipes and elements of this disclosure may be devoid of certain components and/or features: for example, extended wear drill pipes devoid of high carbon steel; extended wear drill pipes devoid of low-strength steels; extended wear drill pipes devoid of coatings