US20190119993A1

US20190119993A1 - Apparatus for axially displacing and tensioning a string of production tubing in a well bore

Info

Publication number: US20190119993A1
Application number: US15/788,885
Authority: US
Inventors: Michael Jonathon Haynes; Kevin Kelm
Original assignee: Progressive Completions Ltd
Current assignee: Progressive Completions Ltd
Priority date: 2017-10-20
Filing date: 2017-10-20
Publication date: 2019-04-25

Abstract

A tensioning tool assembly for supporting a string of oil production piping extending through a well bore includes an outer barrel and a telescoping inner mandrel slidably positioned within the outer barrel. The inner mandrel defines a plurality of axially-spaced slots configured to receive protruding members extending from the outer barrel to fix the relative axial position of the inner mandrel and outer barrel. In this manner, a string of production tubing may be axially displaced by moving inner mandrel to the desired axial position or tension and then rotating inner mandrel to lock the tensioning tool assembly and the attached production tubing. The inner mandrel may further define threaded features for attaching a pull rod and/or a central passageway for supplying fluid to control well pressures.

Description

FIELD OF THE INVENTION

The present subject matter relates generally to the handling of downhole well tools and production tubing strings, and more particularly to axially displacing or placing in tension a production tubing string.

BACKGROUND OF THE INVENTION

Downhole operations and the handling of downhole well tools in completed wells has always presented a certain challenge, especially when working in wells having a natural pressure that is different than atmospheric pressure, necessitating the containment of the well at all times. A further challenge has been the maintenance of well bores which pass through production zones that are not well suited to continuous production. For example, conventional maintenance operations of a well having a production zone which yields both water and oil, gas, or any combination thereof has proven time-consuming and expensive.
For example, in wells which have a mobile water/hydrocarbon interface, the production of hydrocarbon gradually decreases over time until only water or gas is produced from the well. Such wells may require relatively frequent repositioning of a lower end of a string of production tubing in order to recover oil or gas efficiently. The relocation of the tubing string has been a complex process which involved many time-consuming and expensive steps that are well known in the art. It is not difficult to appreciate that there is a need for a more efficient and less costly system for producing oil or gas from such wells.
In addition, as technology has advanced and well operations have resulted in deeper or longer well bores, the length of the corresponding string of production tubing has also increased—along with the weight of such production tubing. Manipulating such a tubing string can result in operational difficulties. For example, moving a tubing string of 4,500′ (1,500 meters), which is not uncommonly encountered in handling downhole well tools, may require a force in excess of 50 tons. The force required is due not only to the considerable weight being lifted but also to the extra force required to unseat anchors and/or packers supporting the tubing string. Such forces may subject the wellhead to potentially damaging stresses. Notably, conventional mechanisms for manipulating these tubing strings may include a spear and grapple assembly which may not be sufficient to support the higher loads associated with longer tubing strings. Moreover, conventional spears assemblies provide no means for assisting with well pressure control, e.g., in the presence of a blowout condition.
Furthermore, it is often desirable to place long strings of production tubing in tension, e.g., to prevent damage due to compression corkscrewing, to provide a relatively straight tubing string for easy and safe manipulation of downhole tools, etc. Conventional tensioning tools have a fixed length or stroke that may be sufficient for accommodating tubing stretch and tensioning tubing strings in relatively shallow wells. However, as well operations get deeper and their associated production tubing strings get longer, such tools often fail to allow for sufficient axial displacement, e.g., to accommodate the tubing stretch associated with the longer tubing string or to facilitate necessary downhole operations.
There therefore exists a need for an apparatus which enables downhole manipulations such as placing a string of production tubing, anchors, or other downhole tools in tension while facilitating improved control of well pressure to eliminate the potential for loss of control.
BRIEF DESCRIPTION OF THE INVENTION
The present disclosure relates generally to a tensioning tool assembly for supporting a string of oil production piping extending through a well bore. The tensioning tool assembly includes an outer barrel and a telescoping inner mandrel slidably positioned within the outer barrel. The inner mandrel defines a plurality of axially-spaced slots configured to receive protruding members extending from the outer barrel to fix the relative axial position of the inner mandrel and outer barrel. In this manner, a string of production tubing may be axially displaced by moving inner mandrel to the desired axial position or tension and then rotating inner mandrel to lock the tensioning tool assembly and the attached production tubing. The inner mandrel may further define threaded features for attaching a pull rod and/or a central passageway for supplying fluid to control well pressures. Additional aspects and advantages of the invention will be set forth in part in the following description, or may be apparent from the description, or may be learned through practice of the invention.
In one exemplary embodiment, a tensioning tool assembly for supporting a string of oil production piping extending through a well bore is provided. The tensioning tool includes an outer barrel defining an axial direction, a radial direction, and a circumferential direction, the outer barrel extending between an upper end and a lower end along the axial direction. A telescoping inner mandrel is slidably positioned within the outer barrel and extends between a first end and a second end along the axial direction. The inner mandrel defines a coupling feature configured for engaging a complementary feature defined on a pull rod such that the pull rod is configured for selectively engaging and moving the inner mandrel along the axial direction.
In another exemplary embodiment, a tensioning tool assembly for supporting a string of oil production piping extending through a well bore is provided. The tensioning tool includes an outer barrel defining an axial direction, a radial direction, and a circumferential direction. The outer barrel includes a first barrel defining a male threaded portion and a second barrel defining a female threaded portion, the male threaded portion and the female threaded portion being engaged to join the first barrel and the second barrel. A telescoping inner mandrel is slidably positioned within the outer barrel and extends between a first end and a second end along the axial direction. The inner mandrel defines a coupling feature configured for engaging a complementary feature defined on a pull rod such that the pull rod is configured for selectively engaging and moving the inner mandrel along the axial direction.
These and other features, aspects and advantages of the present invention will become better understood with reference to the following description and appended claims. The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments of the invention and, together with the description, serve to explain the principles of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

A full and enabling disclosure of the present invention, including the best mode thereof, directed to one of ordinary skill in the art, is set forth in the specification, which makes reference to the appended figures.

FIG. 1 provided a cross-sectional view of a rig apparatus including a tensioning tool assembly according to an exemplary embodiment of the present subj ect matter.

FIG. 2 provides a front view of the exemplary tensioning tool assembly of FIG. 1 according to an exemplary embodiment of the present subject matter.

FIG. 3 provides a front, cross-sectional view of the exemplary tensioning tool assembly of FIG. 1 according to an exemplary embodiment of the present subject matter.

FIG. 4 provides a cross-sectional view of a rig apparatus including a tensioning tool assembly and a pull rod for engaging an inner mandrel of the exemplary tensioning tool assembly according to an exemplary embodiment of the present subject matter.

FIG. 5 provides a close up cross-sectional view of the pull rod engaging the inner mandrel according to an exemplary embodiment of the present subject matter.

FIG. 6 provides a front view of a tensioning tool assembly that may be used in the exemplary rig apparatus of FIG. 1 according to an exemplary embodiment of the present subject matter.

FIG. 7 provides a front, cross-sectional view of the exemplary tensioning tool assembly of FIG. 6 according to an exemplary embodiment of the present subject matter.

FIG. 8 provides a front view of an inner mandrel of the exemplary tensioning tool assembly of FIG. 6 according to an exemplary embodiment of the present subject matter.

FIG. 9 provides a cross-sectional view of the exemplary inner mandrel of FIG. 8, taken along Line 9-9 of FIG. 8.

FIG. 10 provides a schematic view of an elongated flat recess and a plurality of slots defined by the exemplary inner mandrel of FIG. 8.

FIG. 11 provides a front view of an inner mandrel according to another exemplary embodiment of the present subject matter.

Repeat use of reference characters in the present specification and drawings is intended to represent the same or analogous features or elements of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

Reference now will be made in detail to embodiments of the invention, one or more examples of which are illustrated in the drawings. Each example is provided by way of explanation of the invention, not limitation of the invention. In fact, it will be apparent to those skilled in the art that various modifications and variations can be made in the present invention without departing from the scope or spirit of the invention. For instance, features illustrated or described as part of one embodiment can be used with another embodiment to yield a still further embodiment. Thus, it is intended that the present invention covers such modifications and variations as come within the scope of the appended claims and their equivalents.
The present disclosure relates generally to an apparatus for performing downhole operations in well bores which require axial displacement of downhole tools and/or axial displacement of a string of production or well tubing in the well bore. In addition, the present disclosure provides a practical means for maintaining tension or compression on a tubing string in the well bore. Although rig apparatus 64 and a string of production tubing 40 are used below for the purpose of explaining the details of the present subject matter, one skilled in the art will appreciate that the present subject matter may apply to any other suitable oil rig or production tubing configuration. Rig apparatus 64 is used in the discussion below only for the purpose of explanation, and such use is not intended to limit the scope of the present disclosure in any manner.
FIG. 1 shows a cased well bore which passes through a production zone 10 that produces water 12, oil 14, and natural gas 16. The cased well bore consists of a bore generally indicated by reference numeral 18 lined with a casing 20 in a manner well known in the art. A wellhead generally indicated by reference 26 is mounted to a surface casing spool 28. A tubing spool 30 supports a tubing hanger 32 also in a manner well known in the art.
FIG. 1 also illustrates a string of production tubing 40 that is generally configured for extending between wellhead 26 and production zone 10, e.g., to transport well production to the surface. As illustrated, production tubing 40 includes a zone isolating tool generally indicated by the reference 42 located at a bottom of production tubing 40. In accordance with a preferred embodiment of the invention, the zone isolating tool 42 is assembled using packer cups 44. Packer cups 44 may be, for example, packer cups commercially available packer cups that are assembled in a sequence similar to that of a selective acidizing tool known in the art with the exception that two extra cups are added and an upper cup 44 a is oriented upwardly and a lower cup 44 f is oriented downwardly. It should also be understood by those skilled in the art that the two groups of cups 44 a-44 c and 44 d-44 f may be replaced by straddle packers (not illustrated) or inflatable packers (not illustrated) while still achieving substantially the same utility.
Intermediate between the groups of cups 44 a-44 c and 44 d-44 f is an isolated fluid zone 46 which is isolated by the cups or packers from the remainder of a cased well bore when the production tubing 40 is inserted into well bore 18. At least one bore 48 enables fluid communication between an interior of production tubing 40 and the isolated fluid zone 46. Bore 48 may be replaced by a sleeve valve or the like according to alternative embodiments. A bottom end of the zone isolating tool 42 includes a profile nipple (not illustrated) which supports a plug 50 or a control valve (not illustrated).
According to an exemplary embodiment, zone isolating tool 42 is preferably positioned in production zone 10 so that at least the isolated fluid zone 46 is in the zone of interest, namely the oil “sandwich” 14. The downward facing cups 44 b and 44 c and the upward facing cups 44 d and 44 e isolate pressure from the oil sandwich 14 to prevent oil from being forced upwardly or downwardly out of the isolated fluid zone 46 so that oil in the casing is contained within the isolated fluid zone 46. The upward facing cup 44 a prevents gas from being forced down through casing 20 to enter production tubing 40. While some gas may enter perforations that happen to be located between cups 44 a and 44 c and that gas may force past cup 44 e into the isolated fluid zone 46, the amount of gas entering the isolated fluid zone 46 will be minimal. Likewise, while downward facing cup 44 f will prevent most water from the water zone 12 from entering the isolated fluid zone 46, some water may seep through perforations located between cups 44 f and 44 d. A minimal amount of water may therefore be forced into the isolated fluid zone 46 but most water will be excluded by the downward facing cup 44 f and predominantly only oil will be produced through the production tubing 40.
Notably, as oil is produced from the oil sandwich 14, the water layer 12 typically rises. As the water layer 12 rises, an interface between the oil sandwich 14 and the water layer 12 also rises. This permits water to enter the isolated fluid zone 46 and be produced with the oil 14. As will be explained with reference to FIG. 2, production tubing 40 includes a telescoping joint, referred to herein as tensioning tool assembly 100, which is configured for joining production tubing 40 to wellhead 26. More specifically, according to an exemplary embodiment of the present subject matter, tensioning tool assembly 100 is located at or near a top of the string of production tubing 40 and is coupled to tubing hanger 32. As will be discussed in more detail below, tensioning tool assembly 100 is used to raise production tubing 40 in order to adjust the position of isolated fluid zone 46 in response to the change in position of the oil/water interface or to otherwise axially displace production tubing 40 to achieve the desired tension.
Tensioning tool assembly 100 may be attached directly to tubing hanger 32 or may be attached to tubing hanger 32 by a “pup” joint 54 of production tubing. Alternatively, either the tensioning tool assembly 100 or the pup joint or tubing joints 54 may be connected directly to wellhead 26 in a manner well known in the art. When tensioning tool assembly 100 is used for repositioning production tubing 40, it is preferable that a length of travel “A” of tensioning tool assembly 100 is substantially equal to the length “B” of a perforated zone or production zone 10 of potential producing intervals of the casing 20 to permit downhole tools to be positioned anywhere within the perforated zone or zones of interest. In a typical production installation such as shown in FIG. 1, a production packer 56 is located above production zone 10 to isolate the zone from the pressure of gas injected into the annulus of casing 20 to lift oil produced from the oil sandwich 14 to a surface of the well using gas-lift mandrels 58 positioned at intervals along production tubing 40 in a manner well known in the art. Compression anchors 60 help support the compression load of the string of production tubing 40 and prevent damage due to compression corkscrewing and the like. It will also be understood by those skilled in the art that oil may be produced through production tubing equipped with apparatus in accordance with the invention using a pump such as a submersible pump, a progressive cavity pump or the like, or artificial lift or injection systems.
It will be readily understood by persons skilled in the art that the packer cups 44 a-44 f may be replaced by other fluid isolation apparatus such as straddle packers, or inflatable packers, as described above. In order to selectively produce, inject, or stimulate a predominance of a fluid of interest it is only necessary that isolated fluid zone 46 be created by sealing the annulus of casing 20 at or near each interface of the fluid of interest and that the zone isolating tool 42 be axially displaceable so that it is readily repositionable within the well bore 18 to permit the zone isolating tool 42 to be relocated as required to produce a predominance of the fluid of interest.
Referring still to FIG. 1, a rig apparatus 64 is installed over wellhead 12 and is generally configured for assisting with well operations according to an exemplary embodiment. More specifically, for example, rig apparatus 64 is bolted to a top of the wellhead 26 and may include adjustable support pads 66 located respectively at the base of each support leg 68 which may be adjusted so that rig apparatus 64 is level and support legs 68 share the load to be placed on the rig apparatus 64, e.g., when supporting the string of production tubing 40.
According to the illustrated embodiment, a lower support plate 70 is attached to or otherwise supported by support legs 68 to reduce compressive and torsional forces on wellhead 26 which may be induced by the lifting and manipulation of heavy strings of production tubing 40. Located above lower support plate 70 is an upper support plate 72 which is also supported by support legs 68. Reciprocally moveable between lower support plate 70 and upper support plate 72 is a traveling support plate 74. When mounted on support legs 68, traveling support plate 74 is prevented from rotating. Affixed to traveling support plate 74 is a motor 76 that is selectively operated to rotate a lift rod string 80. The motor 76 (or any other suitable lift mechanism) may be a hydraulic motor, an electric motor, or any other suitable mechanical means (such as a rig apparatus) for example.
According to an exemplary embodiment, the stator of motor 76 is mounted to the traveling support plate 74 and the rotor is connected to lift rod string 80, e.g., via a link rod, swivel joint, etc. Lift rod string 80 may further be connected with a piston rod 82 of a hydraulic cylinder 84 which is mounted to upper support plate 72. In this manner, hydraulic cylinder 84 provides the motive of force for displacing lift rod string 80 (and the string of production tubing 40 to which it is attached) along an axial direction A. Although motor 76 is described herein as being used to rotate production tubing 40, it should be appreciated that any other suitable means for rotating production tubing 40 or any other downhole tools are possible and within the scope of the present subject matter.
Typically, wellhead 12 includes one or more spools, e.g., such as a surface spool and a master valve spool (not shown), the structure of each being well known in the art. According to an illustrated embodiment, mounted to a top of the uppermost part of wellhead 12 is a tool entry spool 86, which is the lowermost component of rig apparatus 64. Tool entry spool 86 accommodates a latch tool 88 for connecting a lift rod string 80 to a latch point 90 of tensioning tool assembly 100, directly to a production tube 40, or other downhole tubular when the lift rod string 80 is run into well bore 18.
According to the illustrated embodiment, an annular seal for containing well pressure is mounted to a top flange of tool entry spool 86. For example, according to the illustrated embodiment, the annular seal includes one or more blowout preventers 92. As will be understood by those skilled in the art, other annular seals for containing well pressure can be adapted for use with rig apparatus 64. For example, certain stuffing box structures or multiple ram type or annular preventers can be adapted for such use. Blowout preventer 92 is preferred, however, because of the ease of use and the security of the seal it provides. Preferably, the apparatus includes two blowout preventers 92 connected in sequence in order to increase the safety of the apparatus and to provide extra room between the master valve spool and the uppermost blowout preventer 92 to accommodate latch tools 88 of different lengths. With two or more blowout preventers safety is increased because the preventers can be opened and closed in sequence at each lift rod joint connector in the lift rod string to prevent tears in sealing surfaces which can result from forcing rough surfaces at the connectors through a closed preventer. For this reason, it is preferable that the adjacent preventers be spaced about 10-13 cm (4″-5″) apart to accommodate a lift rod joint connector between them.
Mounted to a top of the uppermost blowout preventer 92 is a tool access spool 94 having at least one tool window 96 or an integral locking mechanism (not illustrated). The tool window 96 permits gripping or locking devices to be inserted for engaging lift rod string 80. In general, tool window 96 permits the lift rod string 80 to be gripped to permit joints to be added to, or removed from, the lift rod string 80. It also permits the lift rod string 80 to be locked against axial movement when joints are being added to, or removed from, the lift rod string 80. For example, the weight of the string of production tubing 40 can be supported at the tool window 96 in low pressure wells while lift rod string joints are being added, or removed. If wells with exceptionally high pressure are being worked, a lock inserted through the tool window 96 prevents the lift rod string 80 from being forced up out of well bore 18 while joints are being added to, or removed from, lift rod string 80.
Referring now generally to FIGS. 2 through 9, tensioning tool assembly 100 will be described according to an exemplary embodiment of the present subject matter. As explained briefly above, tensioning tool assembly 100 may generally be used for supporting a string of oil production piping, such as production tubing 40, for axially displacing downhole tools within the well bore, or for placing the string of production tubing 40 in tension or compression. It should be appreciated that aspects of the present subject matter can be utilized for performing other well operations and tensioning tool assembly 100 is only one exemplary embodiment of an apparatus for performing such functions.
As illustrated, tensioning tool assembly 100 includes an outer barrel 102 that defines an axial direction A, a radial direction R, and a circumferential direction C. Outer barrel 102 extends along the axial direction A between an upper end 104 and an opposite lower end 106. A telescoping inner mandrel 110 is slidably positioned within outer barrel 102 such that inner mandrel 110 is movable along the axial direction A relative to outer barrel 102. More specifically, inner mandrel 110 extends along the axial direction A between a first end 112 and a second end 114. Inner mandrel 110 may telescope or slide relative to outer barrel 102 between a retracted position where inner mandrel 110 is positioned substantially within outer barrel 102 and an extended position where inner mandrel 110 is positioned substantially outside outer barrel 102. More specifically, first end 112 of inner mandrel 110 is positioned proximate upper end 104 of outer barrel 102 in the retracted position and proximate lower end 106 of outer barrel 102 in the extended position.
As best illustrated in FIG. 3, tensioning tool assembly 100 may further include a hanger adapter 120 positioned proximate upper end 104 of outer barrel 102 for joining tensioning tool assembly 100 to a wellhead. For example, hanger adapter 120 may define a threaded top surface 122 (threads not illustrated) configured for receipt within tubing hanger 32 of wellhead 26. According to the illustrated exemplary embodiment, hanger adapter 120 is joined to outer barrel 102 via a threaded connection 124. However, it should be appreciated that according to alternative embodiments, hanger adapter 120 may be coupled to tubing hanger 32 and outer barrel in any other suitable manner. For example, hanger adapter 120 may be formed integrally with outer barrel 102 and may have threads machined on an inner or outer surface.
Referring now specifically to FIGS. 2 and 3, second end 114 of inner mandrel 110 may define features for engaging production tubing 40. More specifically, according to the illustrated embodiment, second end 114 of inner mandrel 110 defines a threaded bottom surface 126 (threads not illustrated) for engaging the top tube of a string of production tubing 40. In this manner, as inner mandrel 110 moves along the axial direction A within outer barrel 102, the string of production tubing 40 and/or attached well bore tools can be moved axially within the well bore 18 to achieve various purposes as described herein.
Inner mandrel 110 may define one or more features for engaging a spear, a pull rod, or another tool for moving inner mandrel 110 within outer barrel 102. For example, referring now briefly to FIGS. 4 and 5, a pull rod 130 may be passed through wellhead 26 and may be configured for engaging inner mandrel 110. In this manner, pull rod 130 may be coupled to rig apparatus 64 for pulling the string of production tubing 40 to the desired tension, compression, or position. In general, inner mandrel 110 defines a coupling feature configured for engaging a complementary feature defined on pull rod 130 such that pull rod 130 is configured for selectively engaging and moving inner mandrel 110 along the axial direction A. More specifically, according to the illustrated embodiment, the coupling feature comprises mandrel threads 132 defined on an inner surface 134 of inner mandrel 110 and the complementary feature comprises pull rod threads 136 defined on a distal end 138 of pull rod 130.
Therefore, pull rod 130 may pass into tensioning tool assembly 100 through outer barrel 102 and may be rotated such that pull rod threads 136 engage mandrel threads 132. Once pull rod 130 is engaged, the relative axial and circumferential positioning of pull rod 130 and inner mandrel 110 are fixed, i.e., such that pull rod 130 may be used to place tension on inner mandrel 110 and production tubing 40. Although a threaded pull rod 130 is described herein, it should be appreciated that any suitable apparatus for selectively engaging and disengaging inner mandrel 110 for supporting the weight of production tubing 40 may be used according to alternative embodiments.
According to the illustrated embodiment, pull rod 130 engages inner mandrel 110 using a threaded connection. However, it should be appreciated that pull rod 130 may be releasably attached to inner mandrel 110 using any other suitable latch mechanism which may include quick-disconnect threads, spears, grapples, keys, collets, friction or slip type tools, releasable packers or rotary taper taps. Once pull rod 130 engages inner mandrel 110, tensioning tool assembly 100 permits the axial displacement of production tubing 40 and the zone isolating tool 42 (or another downhole tool) in the casing 20. This permits a variety of downhole tool manipulations to accomplish various tasks without setting up a derrick or bringing in a crane, killing the well or performing many of the other steps required using prior art methods. Moreover, according to aspects of the present subject matter, tensioning tool assembly 100 may further be used to move a string of production tubing 40 to place it in tension, compression, or to otherwise rotate or move production tubing 40.
Pull rod 130 may also include features for controlling well pressures. For example, according to the illustrated embodiment of FIGS. 4 and 5, pull rod 130 defines a central passageway 140 in fluid communication with an internal passageway 142 of inner mandrel 110. Using this central passageway 140, a well operator may pump a drilling fluid or mud through central passageway 140, into internal passageway 142, and through production tubing 40 to control pressures within well bore 18. It should be appreciated that according to alternative embodiments, pull rod may not define a central passageway for pumping fluids.
Referring now to FIGS. 8 through 10, outer barrel 102 and inner mandrel 110 may further define one or more features for locking the inner mandrel 110 relative to the outer barrel 102. In this manner, for example, the string of production tubing 40 may be pulled to the desired tension (as described above) and locked in tension. For example, according to the illustrated embodiment, inner mandrel 110 defines a plurality of slots 150 spaced apart along the axial direction A, each of the slots 150 extending substantially along the circumferential direction C around inner mandrel 110. It should be appreciated that as used herein, terms of approximation, such as “approximately,” “substantially,” or “about,” refer to being within a ten percent margin of error. In addition, outer barrel 102 defines one or more protruding members 152 (see FIG. 9) such as bosses or lug nuts that extend inward along the radial direction R from outer barrel 102 toward inner mandrel 110. In general, protruding members 152 are configured for engaging one or more of slots 150 to lock the axial position of inner mandrel 110 within outer barrel 102.
More specifically, according to the illustrated embodiment, the plurality of slots 150 include six sets of slots 150, each set being spaced apart by approximately 12 centimeters along the axial direction A. For simplicity, only one set of slots 150 is illustrated schematically in FIG. 10. However, it should be appreciated that each set of slots 150 may include any suitable number of circumferentially spaced slots 150 and a corresponding number of protruding members 152 according to alternative embodiments. For example, the illustrated embodiment includes three circumferentially spaced slots 150 for engaging three circumferentially spaced protruding members 152 defined on outer barrel 102. It should be appreciated that the slots 150 and protruding members 152 illustrated herein are used only for the purpose of explaining aspects of the present subject matter and are not intended to be limiting. For example, although six axially spaced slots 150 are illustrated, it should be appreciated that any suitable number, spacing, geometry, and configuration of slots may be used according to alternative embodiments. For example, inner mandrel 110 may define 10, 100, or any other suitable number of slots 150.
FIG. 8 illustrates a schematic view of potential sliding paths of protruding members 152 along inner mandrel 110. As illustrated, slots 150 extend at an angle 156 relative to the circumferential direction C. More specifically, angle 156 may be between about 0 and 30 degrees, between about 5 and 15 degrees, about 10 degrees, or may be any other suitable angle. In addition, each of slots 150 may have a closed end for stopping the rotate of inner mandrel 110. As illustrated in FIG. 10, slots 150 may be J-shaped slots that define an axial recess 158 for ensuring engagement with protruding member 152. Alternatively, slots 150 may be formed to have any suitable shape and configuration.
Notably, the inner diameter of outer barrel 102 is substantially similar or slightly larger than the outer diameter of inner mandrel 110. To allow inner mandrel 110 to slide within outer barrel 102, an outer surface 162 of inner mandrel 110 defines an elongated flat recess 164 between the axially spaced-apart slots 150 to provide a path of travel for protruding members 152. More specifically, elongated flat recess 164 is used to define a radial gap 166 between inner mandrel 110 and outer barrel 102, as best shown in FIGS. 8 through 11. In this manner, protruding members 152 may be positioned within radial gap 166 and slide axially along elongated flat recess 164 to allow inner mandrel 110 to slide within outer barrel 102. More specifically, for example, protruding members 152 define a height 168 that is less than the height of radial gap 166 such that inner mandrel 110 is slidable along the axial direction A relative to outer barrel 102 when the protruding members 152 are positioned within radial gap 166.
When inner mandrel 110 is pulled to an axial position where protruding members 152 are at the same axial position as a set of slots 150, inner mandrel 110 may be rotated to position protruding members 152 within those slots 150 and lock the axial position of inner mandrel 110. According to the illustrated embodiment, protruding members 152 are positioned proximate lower end 106 of outer barrel 102 to permit inner mandrel 110 to reach a fully extended position before mandrel head 170 engages protruding members 152 to retain inner mandrel 110 within outer barrel 102.
According to an exemplary embodiment of the present subject matter, tensioning tool assembly 100 may further define features for locking the angular position of inner mandrel 110 within outer barrel 102 when inner mandrel 110 is in the fully extended position. More specifically, according to the illustrated embodiment of FIG. 11, inner mandrel 110 defines one or more locking recesses 174 proximate first end 112 of inner mandrel 110. Locking recesses 174 may be, for example, semicircular cutouts defined in mandrel head 170 that are configured for engaging protruding members 152 when inner mandrel 110 is in the extended position. In this manner, when protruding members 152 are engaged within locking recesses 174, the relative angular position of inner mandrel 110 and outer barrel 102 are fixed, such that inner mandrel 110 and production tubing 40 may be rotated by rotating outer barrel 102. It should be appreciated that other mechanisms for fixing the angular position of inner mandrel 110 relative to outer barrel 102 are possible and within the scope of the present subject matter.
Referring now to FIGS. 6 and 7, outer barrel 102 may include any suitable number of segments or barrels coupled together to form tensioning tool assembly 100 having a suitable axial length and extension length desirable for a particular application. For example, according to the illustrated embodiments, outer barrel 102 includes a first barrel 180 defining a male threaded portion 182 and a second barrel 184 defining a female threaded portion 186. As illustrated, male threaded portion 182 and female threaded portion 186 are engaged to form a joint 188 that couples first barrel 180 and second barrel 184. According to the illustrated embodiment, joint 188 defines a joint thickness 190 that is substantially equal to a wall thickness 192 of first barrel 180 and second barrel 184. In this manner, joint 188 is smooth and includes no irregularities that may prevent inner mandrel 110 from sliding smoothly within outer barrel 102.
In order to prevent leaks between production zone 10 and wellhead 26, tensioning tool assembly 100 is preferably a fluid tight assembly. In this regard, referring for example to FIGS. 3 and 8, inner mandrel 110 defines one or more circumferential grooves 194 on an outer surface 162 proximate first end 112 of inner mandrel 110. Tensioning tool assembly 100 further includes one or more resilient annular seals 196, e.g., O-rings, positioned within circumferential grooves 194 to provide a fluid seal between inner mandrel 110 and outer barrel 102. Annular seals 196 are preferably high pressure fluid seals to ensure that high pressure fluids do not escape from tensioning tool assembly 100. In this manner, hydrocarbons, drilling mud, and/or other fluids may not leak out of tensioning tool assembly 100 as inner mandrel 110 moves between the extended and retracted positions.
Tensioning tool assembly 100 described above provides an effective means of axially displacing or tensioning a string of production tubing within a well bore. A long production tubing string tends to sag under its own weight. This is disadvantageous if a surface-driven reciprocating pump is used to recover hydrocarbons from the well. Such tubing strings may be anchored at their bottom end by an anchor member, such as a packer connected to the bottom of the production tubing string. A top of the production tubing string includes tensioning tool assembly 100 connected to a tubing hanger in a wellhead. A lifting mechanism is temporarily installed on the wellhead to enable tensioning tool assembly 100 to be retracted until the tubing string is under a desired tension to prevent undesirable sag as hydrocarbon is produced from the well.
Using tensioning tool assembly 100 for tensioning a production tubing string advantageously simplifies the conventional method in which a pup joint having a desired length has to be prepared to replace a top production tubing joint. As is well known, it is a time-consuming, expensive and potentially hazardous operation to determine a required length for the pup joint, and to install it. However, with a locking tensioning tool assembly 100 in accordance with the present subject matter, the operation is quickly, easily, and inexpensively done without removing the wellhead and without the dangers of moving tubing that is under pressure or working over an open well bore. Tensioning tool assembly 100 also permits the tubing string to be re-tensioned without removing the wellhead or killing the well if, over time, the tubing string loses its tension.
This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they include structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims.

Claims

What is claimed is:

1. A tensioning tool assembly for supporting a string of oil production piping extending through a well bore, the tensioning tool comprising:

an outer barrel defining an axial direction, a radial direction, and a circumferential direction, the outer barrel extending between an upper end and a lower end along the axial direction; and

a telescoping inner mandrel slidably positioned within the outer barrel, the inner mandrel extending between a first end and a second end along the axial direction, the inner mandrel defining a coupling feature configured for engaging a complementary feature defined on a pull rod such that the pull rod is configured for selectively engaging and moving the inner mandrel along the axial direction.

2. The tensioning tool assembly of claim 1, wherein the coupling feature comprises mandrel threads defined on an inner surface of the inner mandrel and the complementary feature comprises pull rod threads defined on a distal end of the pull rod.

3. The tensioning tool assembly of claim 1, wherein the pull rod defines a central passageway in fluid communication with an internal passageway of the inner mandrel.

4. The tensioning tool assembly of claim 1, wherein the relative axial positioning and the relative circumferential positioning of the pull rod and the inner mandrel are fixed when the coupling feature engages the complementary feature.

5. The tensioning tool assembly of claim 1, wherein the outer barrel comprises:

a first barrel defining a male threaded portion; and

a second barrel defining a female threaded portion, the male threaded portion and the female threaded portion being engaged to join the first barrel and the second barrel.

6. The tensioning tool assembly of claim 5, wherein a joint is defined where the male threaded portion engages the female threaded portion, the joint defining a joint thickness that is substantially equal to a wall thickness of the first barrel and the second barrel.

7. The tensioning tool assembly of claim 1, wherein the inner mandrel defines one or more circumferential grooves on an outer surface proximate the first end of the inner mandrel, the tensioning tool assembly further comprising one or more resilient seals positioned within the circumferential grooves to provide a fluid seal between the inner mandrel and the outer barrel.

8. The tensioning tool assembly of claim 1, wherein the inner mandrel defines a plurality of slots extending substantially along the circumferential direction around the inner mandrel, the plurality of slots being spaced apart along the axial direction, and wherein the outer barrel defines one or more protruding members proximate the lower end of the outer barrel, the protruding members being configured for receipt within the slots to fix an axial position of the inner mandrel within the outer barrel.

9. The tensioning tool assembly of claim 8, wherein the plurality of slots extend at an angle relative to the circumferential direction.

10. The tensioning tool assembly of claim 9, wherein the angle is between about 1 and 20 degrees.

11. The tensioning tool assembly of claim 8, wherein an outer surface of the inner mandrel defines an elongated flat recess to define a radial gap between the inner mandrel and the outer barrel, the protruding members defining a height that is less than the radial gap such that the inner mandrel slidable along the axial direction relative to the outer barrel when the protruding members are positioned within the radial gap.

12. The tensioning tool assembly of claim 11, wherein the inner mandrel defines one or more locking recesses proximate the first end of the inner mandrel, the locking recesses being configured for engaging the protruding members to prevent the inner mandrel from rotating within the outer barrel.

13. The tensioning tool assembly of claim 8, wherein the plurality of slots comprises six slots, each of the six slots being spaced apart from adjacent slots by approximately 12 centimeters along the axial direction.

14. The tensioning tool assembly of claim 1, wherein the upper end of the outer barrel is threaded for receipt in a tubing hanger mounted to a wellhead.

15. A tensioning tool assembly for supporting a string of oil production piping extending through a well bore, the tensioning tool comprising:

an outer barrel defining an axial direction, a radial direction, and a circumferential direction, the outer barrel comprising a first barrel defining a male threaded portion and a second barrel defining a female threaded portion, the male threaded portion and the female threaded portion being engaged to join the first barrel and the second barrel; and

16. The tensioning tool assembly of claim 15, wherein a joint is defined where the male threaded portion engages the female threaded portion, the joint defining a joint thickness that is substantially equal to a wall thickness of the first barrel and the second barrel.

17. The tensioning tool assembly of claim 15, wherein the coupling feature comprises mandrel threads defined on an inner surface of the inner mandrel and the complementary feature comprises pull rod threads defined on a distal end of the pull rod, and wherein the relative axial positioning and the relative circumferential positioning of the pull rod and the inner mandrel are fixed when the pull rod threads engage the mandrel threads.

18. The tensioning tool assembly of claim 15, wherein the pull rod defines a central passageway in fluid communication with an internal passageway of the inner mandrel.

19. The tensioning tool assembly of claim 15, wherein the inner mandrel defines one or more circumferential grooves on an outer surface proximate the first end of the inner mandrel, the tensioning tool assembly further comprising one or more resilient seals positioned within the circumferential grooves to provide a fluid seal between the inner mandrel and the outer barrel.

20. The tensioning tool assembly of claim 15, wherein the inner mandrel defines a plurality of slots extending substantially along the circumferential direction around the inner mandrel, the plurality of slots being spaced apart along the axial direction, and wherein the outer barrel defines one or more protruding members proximate a lower end of the outer barrel, the protruding members being configured for receipt within the slots to fix an axial position of the inner mandrel within the outer barrel.