SYSTEMS AND METHODS FOR MAKING AND BREAKING THREADED JOINTS USING ORBITAL MOTIONS
A method for making a threaded joint between first and second tubulars, each tubular including a central axis, a first end, a second end, a throughbore extending between the first second ends, an internally threaded box-end connector at the first end, and an externally threaded pin-end connector at the second end, the method including: (a) moving the first tubular axially relative to the second tubular to position the pin-end connector of the first tubular at least partially within the box-end connector of the second tubular. In addition, the method includes (b) orbiting the pin-end connector of the first tubular about the central axis of the second tubular; and (c) rotating the first tubular about the central axis of the first tubular during (b). Further, the method includes (d) threading the pin-end connector of the first tubular into the box-end connector of the second tubular dining (b) and (c).
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This application claims benefit of U.S. provisional patent application Ser. No. 61/906,696 filed Nov. 20, 2013, and entitled “Systems and Methods for Making and Breaking Threaded Joints Using Orbital Motions,” which is hereby incorporated herein by reference in its entirety for all purposes.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENTNot applicable.
BACKGROUNDThe invention relates generally to the makeup and breakup of threaded joints and connections. More particularly, the invention relates to the makeup and breakup of threaded joints in tubular strings used in oil and gas drilling and production operations.
A variety of conduits, flowlines, and tubular strings used in oil and gas operations, such as drillstrings, risers, conductors, tubings and casings, are formed threadably connecting tubular members end-to-end. For example, when drilling an oil and gas well, a plurality of rigid elongate drill pipe sections are typically threadably connected end-to-end to form a drillstring with a drill bit disposed at the lower end thereof. During drilling operations, the drill bit is rotated (e.g., by a top drive or a mud motor) about a central axis with weight on bit (“WOB”) applied such that the bit engages the earthen formation to lengthen the borehole. As the newly formed borehole lengthens, additional pipe sections are threadably connected to the upper most end of the drillstring. Specifically, during such “makeup” operations, each new pipe section is lowered such that its lower end engages the upper most end of the drillstring and is coaxially aligned with the central axis of the drillstring. Thereafter, the new pipe section is rotated about the central axis of the drillstring such that threads disposed on its lower end engage with corresponding threads on the upper most end of the drillstring. Once the new pipe section is threaded onto the drillstring, a final makeup torque is applied (e.g., by a wrench or other similar tool) to ensure that the connection is fully made up. This process is repeated with new pipe sections being added to the upper end of the drilistring as the drill bit lengthens the borehole until the desired depth is achieved.
To remove the drillstring from the borehole the drillstring is lifted from the borehole as pipe sections at the upper end of the drillstring are de-coupled therefrom. During such “breakup” operations, torque is applied to each threaded connection to rotate each section of drill pipe about the central axis of the drillstring in order to disengage the threaded connection between the drill pipe section and the rest of the drilistring. In this manner the drillstring is disassembled as it is withdrawn from the borehole. During conventional breakup operations, coaxial alignment of each drill pipe section and the rest of the drillstring is substantially maintained as each successive drill pipe section is rotated to de-couple the same from the drillstring.
During both makeup and breakup operations, frictional forces resist threaded engagement and disengagement, respectively, of the pipe joints being threaded to and unthreaded from, respectively, the drillstring. Relatively large torque loads may be necessary to overcome the frictional forces. However, the application of excessive torque loads can result in damage and/or excessive wear to the pipe joint threads. Further, as the applied torque loads increase, the tools (e.g., wrenches, power tongs, etc.) used to apply torque to the pipe joints can leave gouges and/or scratches to the outer surface of each drill pipe section, potentially decreasing the useful life of the pipe joints.
BRIEF SUMMARY OF THE DISCLOSURESome embodiments are directed to a method for making a threaded joint between a first elongate tubular and a second elongate tubular, each tubular including a central axis, a first end, a second end opposite the first end, a throughbore extending between the first end and the second end, an internally threaded box-end connector at the first end, and an externally threaded pin-end connector at the second end. In an embodiment, the method comprises (a) moving the first tubular axially relative to the second tubular to position the pin-end connector of the first tubular at least partially within the box-end connector of the second tubular, in addition, the method comprises (b) orbiting the pin-end connector of the first tubular about the central axis of the second tubular. Further, the method comprises (c) rotating the first tubular about the central axis of the first tubular in the opposite direction during (b). Still further, the method comprises (d) threading the pin-end connector of the first tubular into the box-end connector of the second tubular during (b) and (c).
Other embodiments are directed to a method for breaking a threaded joint between a first elongate tubular and a second elongate tubular, each tubular including a central axis, a first end, a second end opposite the first end, a throughbore extending between the first end and the second end, an internally threaded box-end connector at the first end, and an externally threaded pin-end connector at the second end. In an embodiment, the method comprises (a) orbiting the pin-end connector of the first tubular about the central axis of the second tubular. In addition, the method comprises (b) rotating the first tubular about the central axis of the first tubular during (a) in the opposite direction. Further, the method comprises (c) unthreading the pin-end connector of the first tubular from the box-end connector of the second tubular during (a) and (b). Still further, the method comprises (d) moving the first tubular axially relative to the second tubular to remove the pin-end connector of the first tubular from the box-end connector of the second tubular.
Still other embodiments are directed to a method for assembling a tubular string for an oil and gas operation, wherein the tubular string comprises a plurality of elongate threaded tubulars, each tubular including a central axis, a first end, a second end opposite the first end, a throughbore extending between the first end and the second end, an internally threaded box-end connector disposed at the first end, and an externally threaded pin-end connector disposed at the second end. In an embodiment, the method comprises (a) lowering the tubular string into a borehole. In addition, the method comprises (b) lowering a first tubular axially toward the tubular string to position the pin-end connector of the first tubular into a box-end connector disposed at an upper end of the tubular string. Further, the method comprises (c) orbiting the pin-end connector of the first tubular about the central axis of the tubular string. Still further, the method comprises (d) rotating the first tubular about the central axis of the tubular string during (c). Also, the method comprises (e) threading the pin-end connector of the first tubular into the box end connector of the tubular string during (c) and (d) to lengthen the tubular string.
Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood, The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which
The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.
Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily 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 in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis.
In the following description and figures, embodiments of systems and methods for making and breaking threaded joints using orbital motions are described for use with a plurality of tubular sections making up a drilistring. However, it should be appreciated that embodiments of the systems and methods described herein may be utilized in wide variety of systems and applications which employ threaded connections to make up adjacent tubular sections while still complying with the principles disclosed herein, such as for example, for production tubing sections and casing pipe sections. In addition, embodiments of the systems and methods described herein may be utilized to facilitate the makeup of other known threaded connections, such as, for example, a threaded connection between a bolt and nut. Therefore, use of embodiments of the systems and methods described herein to facilitate the threaded connection between adjacent drillstring sections is only one of many potential uses thereof. Thus, any reference to drillstrings and related subject matter is merely included to provide context to the description contained herein and is in no way meant to limit the scope thereof.
Referring now to
Riser 40 has a central axis 45 and includes a first or upper end 40a coupled to platform 20 and a second or lower end 40b coupled to LMRP 27. In this embodiment, riser 40 is made up of a plurality of elongate riser sections 44 coupled end-to-end at joints 46. In some embodiments, joints 46 are threaded joints; however, it should be appreciated that other types of connections are possible, such as, for example, bolted flange connections. Drilling operations are carried out by a tubular string or drillstring 50 supported by platform 20 and extending through riser 40, LMRP 27, BOP 25, and into cased wellbore 14. In this embodiment, drillstring 50 is made up of a plurality of elongate tubular sections 110 coupled end-to-end at threaded joints 120. An annulus 48 is formed between drillstring 50 and riser 40.
During drilling operations, a drill bit 32 disposed at the lower end of drillstring 50 is rotated as weight-on-bit (WOB) is applied to drill wellbore 14. During this process, drilling fluid (e.g., mud) is pumped from platform 20, down drill string 50, out the face of drill bit 32, and back up annulus 48.
Referring now to
Outer surface 112c of each body 112 is disposed at an outer diameter D110o, and inner surface 112d of each body 112 is disposed at an inner diameter D110i. Outer surface 112c is cylindrical between upper end 112a and pin-end connector 118, and is frustoconical along connector 118. Thus, outer diameter D110o is uniform between end 112a and pin-end connector 118, but decreases moving axially along pin-end connector 118 toward lower end 112b. Inner surface 112d is cylindrical between lower end 112b and box-end connector 116, and is frustoconical along connector 116. Thus, inner diameter D110i is uniform between end 112b and box-end connector 116, but increases moving axially along box-end connector 116 toward lower end 112a.
For purposes of clarity and further explanation, the upper pipe or drillstring section 110 of segment 100 will be referred to as section 110A, the lower pipe or drillstring section 110 of segment 100 will be referred to as section 110B, and axes 125 of sections 110A, 110B will be referred to as axes 125A, 125B, respectively. When sections 110A, 110B, are threadably connected together end-to-end at joint 120 with mating connectors 116, 118 as shown in
As previously described, threaded joints between tubulars used in oil and gas operations are conventionally made-up and broke-up with the tubulars coaxially aligned. However, in embodiments described herein, the makeup and breakup of threaded joints between tubulars is performed, at least partially, without the tubulars being coaxially aligned. More specifically, referring now to
The method for making up threaded joint 120 shown in
In at least some embodiments, once section 110A begins rotating about axis 125A (whether by torque T130 and/or force F130′ alone or in combination with an external device), a second frictional force F130″ also acts on sections 110A, 110B to resist slipping between threads 117, 119 due to the rotation of section 110A relative to section 110B. Force F130″ is analogous to the friction force that must be overcome during conventional makeup operations. However, as is shown in
During makeup of joint 120 according to the method illustrated in
Referring now to
The method for making up threaded joint 120 shown in
Since mating threaded connectors 118, 116 of sections 110A, 110B, respectively, are tapered, as joint 120 is made-up according to the method illustrated in
Referring now to
The method for breakup of threaded joint 120 shown in
Further, as section 110A rotates about its axis 125B, a second frictional force F131″ resists slipping between threads 117, 119 due to rotation of section 110A about axis 125A relative to section 110B. Force F131″ is analogous to the friction that resists relative rotation of sections 110A, 110B during conventional breakup operations. However, as is shown in
Referring now to
The method for breaking up threaded joint 120 shown in
Referring now to
In this embodiment, device 200 orients section 110A parallel to section 110B to produce the relative motions of the sections 110A, 110B as described above and shown in
In the manner described, upper section 110A is manipulated and moved relative to a stationary lower section 110B to makeup and breakup threaded joint 120. However, it should be appreciated that such relative motion of sections 110A, 110B can also be accomplished by manipulating lower section 110B or manipulating both sections 110A, 110B. For example, lower section 110B can be manipulated and moved relative to a stationary upper section 110A (lower section 110B orbited about axis 125A of upper section 110A with section 110B parallel to section 110A or with sections 110A, 110B skewed or angled relative to each other). Referring briefly to
Referring now to
In the manner described, systems and methods described herein offer the potential to reduce the total torque necessary to makeup and breakup threaded joints between tubular sections by inducing orbital motion(s) in one or both tubular sections (e.g., sections 110A, 110B). Reduced torque loads in turn offer the potential to increase the useful life of the tubular sections by reducing damage and/or wear on the mating threads (e.g., threads 117, 119) and outer surfaces (e.g., surface 112c) of tubular sections. In addition, the reduced torque loads also results in a reduced value of the resulting residual stresses which occur within such threaded connections, which thereby guards against subsequent loosening of the joint after makeup.
While embodiments disclosed herein have included methods of makeup and breakup of tubular sections 110A, 110B, it should be appreciated that embodiments of the systems and methods disclosed herein may be utilized to facilitate the makeup for other types of threaded connections. For example, referring now to
While embodiments disclosed herein have been described as being used in an offshore drilling and/or production system system 10) in other embodiments, the principles disclosed herein may be applied to any drilling and/or production system (e.g., a land-based drilling and/or production system) while still complying with the principles disclosed herein. Thus, any reference in the above disclosure to offshore drilling and/or production systems is merely included to provide context to the description above and is in no way meant to limit the scope thereof. Additionally, while embodiments disclosed herein have described the methods and/or devices as being carried out on sections of drill pipe, it should be appreciated that in other embodiments, the methods and/or device disclosed herein may be used to perform makeup/breakup operations for any type of elongate threaded tubular member, such as, for example, tubing, casing pipes, risers, etc. Thus, any mention of drill pipes is not meant to limit the application of the principles disclosed herein in any way, and is only included to provide context to the description above.
Further, while embodiments disclosed herein have included threaded connections 118, 116 that are tapered, it should he appreciated that in other embodiments, threaded connections 118, 116 are not tapered as for the nut and threaded rod example while still complying with the principles disclosed herein. Referring to
During makeup of joint 120 with cylindrical threaded connections according to the method illustrated in
The embodiments described in reference to
The embodiments described in reference to
While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.
Claims
1. A method for making a threaded joint between a first elongate tubular and a second elongate tubular, each tubular including a central axis, a first end, a second end opposite the first end, a throughbore extending between the first end and the second end, an internally threaded box-end connector at the first end, and an externally threaded pin-end connector at the second end, the method comprising:
- (a) moving the first tubular axially relative to the second tubular to position the pin-end connector of the first tubular at least partially within the box-end connector of the second tubular;
- (b) orbiting the pin-end connector of the first tubular about the central axis of the second tubular;
- (c) rotating the first tubular about the central axis of the first tubular during (b); and
- (d) threading the pin-end connector of the first tubular into the box-end connector of the second tubular during (b) and (c).
2. The method of claim 1, further comprising maintaining the central axis of the first tubular parallel to the central axis of the second tubular during (b) and (c).
3. The method of claim 2, further comprising:
- radially offsetting the central axis of the first tubular from the central axis of the second tubular by a radial offset distance;
- decreasing the radial offset distance during (d).
4. The method of claim 1, further comprising orienting the first tubular at an acute angle θ relative to the second tubular during (b) and (c).
5. The method of claim 4, further comprising decreasing angle θ during (d).
6. The method of claim 1, further comprising spiraling the central axis of the second tubular inward relative to the central axis of the first tubular during (b) and (c).
7. The method of claim 1, wherein (c) occurs in response to (b).
8. The method of claim 1, further comprising driving the rotation of the first tubular about the central axis of the first tubular during (c) with a device removably coupled to the first tubular.
9. A method for breaking a threaded joint between a first elongate tubular and a second elongate tubular, each tubular including a central axis, a first end, a second end opposite the first end, a throughbore extending between the first end and the second end, an internally threaded box-end connector at the first end, and an externally threaded pin-end connector at the second end, the method comprising:
- (a) orbiting the pin-end connector of the first tubular about the central axis of the second tubular;
- (b) rotating the first tubular about the central axis of the first tubular during (a); and
- (c) unthreading the pin-end connector of the first tubular from the box-end connector of the second tubular during (a) and (b); and
- (d) moving the first tubular axially relative to the second tubular to remove the pin-end connector of the first tubular from the box-end connector of the second tubular.
10. The method of claim 9, further comprising maintaining the central axis of the first tubular parallel to the central axis of the second tubular during (a) and (b).
11. The method of claim 10, further comprising increasing a radial offset distance between the central axis of the first tubular and the central axis of the second tubular during (d).
12. The method of claim 9, further comprising increasing an acute angle θ between the central axis of the first tubular and the central axis of the second tubular during (a) and (b).
13. The method of claim 9, further comprising spiraling the central axis of the second tubular outward relative to the central axis of the first tubular during (a) and (b).
14. The method of claim 9, wherein (b) occurs in response to (a).
15. A method for assembling a tubular string for an oil and gas operation, wherein the tubular string comprises a plurality of elongate threaded tubulars, each tubular including a central axis, a first end, a second end opposite the first end, a throughbore extending between the first end and the second end, an internally threaded box-end connector disposed at the first end, and an externally threaded pin-end connector disposed at the second end, the method comprising:
- (a) lowering the tubular string into a borehole;
- (b) lowering a first tubular axially toward the tubular string to position the pin-end connector of the first tubular into a box-end connector disposed at an upper end of the tubular string;
- (c) orbiting the pin-end connector of the first tubular about the central axis of the tubular string;
- (d) rotating the first tubular about the central axis of the tubular string during (c); and
- (e) threading the pin-end connector of the first tubular into the box end connector of the tubular string during (c) and (d) to lengthen the tubular string.
16. The method of claim 15, further comprising maintaining the central axis of the first tubular parallel to the central axis of the tubular string during (c) and (d).
17. The method of claim 16, further comprising decreasing a radial offset distance between the central axis of the first tubular and the central axis of the tubular string during (e).
18. The method of claim 15, further comprising decreasing an acute angle θ between the central axis of the first tubular and the central axis of the tubular string during (e).
19. The method of claim 15, wherein (d) occurs in response to (c).
20. The method of claim 15, further comprising:
- (f) lowering the tubular string further into the borehole after (e);
- (g) lowering a second tubular axially toward the tubular string to position the pin-end connector of the second tubular into a box-end connector disposed at an upper end of the first tubular;
- (h) orbiting the pin-end connector of the second tubular about the central axis of the first tubular;
- (i) rotating the second tubular about the central axis of the first tubular during (h); and
- (j) threading the pin-end connector of the second tubular into the box end connector of the first tubular during (h) and (i) to lengthen the tubular string.
21. A method for making a threaded connection between a threaded rod and a bolt, where the threaded rod includes a central axis, a first end, a second end opposite the first end, a radially outer surface extending between the first end and second end, and where the radially outer surface includes a set of external threads, and where the bolt includes a central axis, a first end, a second end opposite the first end, and has a throughbore extending axially between the first end and second end, and where the bolt has a set of internal threads, the method comprising:
- (a) disposing the bolt onto the threaded rod such that the axis of the bolt is parallel to the axis of the threaded rod;
- (b) orbiting the bolt about the central axis of the threaded rod;
- (c) rotating the bolt about the central axis of the bolt during (b); and
- (d) threadably engaging the internal threads of the bolt with the external threads of the threaded rod during (b) and (c).
22. The method of claim 21, further comprising maintaining the central axis of the bolt parallel to the central axis of the threaded rod during (b) and (c).
23. The method of claim 21, further comprising decreasing a radial offset distance between the central axis of the bolt and the central axis of the threaded rod during (d).
24. The method of claim 21, further comprising decreasing an acute angle θ between the central axis of the first tubular and the central axis of the tubular string during (d).
Type: Application
Filed: Nov 20, 2014
Publication Date: May 21, 2015
Applicant: BP Corporation North America Inc. (Naperville, IL)
Inventor: PIERRE A. BEYNET (Houston, TX)
Application Number: 14/548,412
International Classification: E21B 17/042 (20060101);