Patent Application
20190119993
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.
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.
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.
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.
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.
Intermediate between the groups of cups 44a-44c and 44d-44f 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 44b and 44c and the upward facing cups 44d and 44e 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 44a 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 44a and 44c and that gas may force past cup 44e into the isolated fluid zone 46, the amount of gas entering the isolated fluid zone 46 will be minimal. Likewise, while downward facing cup 44f 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 44f and 44d. 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 44f 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
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
It will be readily understood by persons skilled in the art that the packer cups 44a-44f 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
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
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
Referring now specifically to
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
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
Referring now to
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
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
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
Referring now to
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
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.
