Patent Publication Number: US-7905289-B2

Title: Double-acting jar compounder

Description:
TECHNICAL FIELD 
     This document relates to compounders, in particular to double-acting compounders. 
     BACKGROUND 
     Compounders are used in tandem with jarring devices in order to enhance the jarring impact of the jarring device. Compounders use inner spring mechanisms in order to store the additional energy that is released to increase the jar. U.S. Pat. No. 5,931,242 describes a compounder that incorporates a movable piston disposed within a fluid chamber between inner and outer cylindrical assemblies to provide compounding in either jarring direction. 
     SUMMARY 
     A double-acting compounder is disclosed having a first end and a second end, and comprising an outer housing, an upper mandrel, and a lower mandrel. The outer housing defines the first end. The upper mandrel is at least partially disposed telescopically within the outer housing to define an uphole fluid chamber between the upper mandrel and the outer housing, the upper mandrel defining the second end. The lower mandrel is at least partially disposed telescopically within the outer housing to define a downhole fluid chamber between the lower mandrel and the outer housing. The uphole fluid chamber and the downhole fluid chamber each contain fluid, have a variable stroke-dependent volume, and are sealed at an uphole end and a downhole end. The upper mandrel has a first shoulder engagable with and facing a second shoulder of the lower mandrel to move the lower mandrel during at least a portion of a stroke. 
     These and other aspects of the device and method are set out in the claims, which are incorporated here by reference. 
    
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
       Embodiments will now be described with reference to the figures, in which like reference characters denote like elements, by way of example, and in which: 
         FIGS. 1A-C  is an exploded side elevation view, in section, of a double-acting compounder fully compressed. 
         FIGS. 2A-C  is an exploded side elevation view, in section, of the double-acting compounder of  FIGS. 1A-C  fully extended. 
         FIGS. 3A-C  is an exploded side elevation view, in section, of the double-acting compounder of  FIGS. 1A-C  in a neutral position. 
         FIG. 4  is a partial side elevation view, in section of an embodiment of a shoulder configuration for a double-acting compounder. 
         FIG. 5  is a cross sectional view illustrating the relationship between sealing interfaces in an annular fluid chamber. 
         FIG. 6  is a cross sectional view further illustrating the relationship between sealing interfaces in a non-annular fluid chamber. 
         FIG. 7  is a schematic side elevation view, showing a simplified version of the double-acting compounder of  FIGS. 1A-C . 
         FIG. 8  is an exploded side elevation view, in section, of another embodiment of a double-acting compounder in a neutral position. 
         FIG. 9  is an exploded side elevation view, in section, of the double-acting compounder of  FIG. 8  fully compressed. 
         FIG. 10  is an exploded side elevation view, in section, of the double-acting compounder of  FIG. 8  fully extended. 
     
    
    
     DETAILED DESCRIPTION 
     Immaterial modifications may be made to the embodiments described here without departing from what is covered by the claims. 
     Jars provide a large transient force impact to a tubing string in either an upward or downward direction. A jar may have, for example, an inner tubular disposed within an outer tubular, defining a chamber in between the two. The chamber may contain hydraulic fluid in the form of gas or liquid, for example. In some cases, a mechanical spring may be used. A tensile or compressive force is applied, through the tubing string, to either the outer tubular or the inner tubular of the jar, forcing the outer tubular and inner tubular to move relative to one another. The relative movement between the two is initially restricted within the chamber, such that the energy of the tensile or compressive force builds up in the tubing string. As soon as the outer tubular and inner tubular move far enough relative to one another to clear the initial restriction, the energy built up in the tubing string is transferred into rapid relative motion between the inner tubular and the outer tubular. Jarring shoulders on both the inner tubular and outer tubular then impact one another, releasing a large amount of kinetic energy into the tubing string and causing a striking blow to the tubing string. 
     A double-acting compounder may be used with a double-acting jar, in order to compound the jarring force of the jar in both directions. A compounder may be connected, for example, either directly or indirectly to the jar in the tubing string. By applying a compressive or tensile force to the tubing string, the compounder uses, for example, a fluid or mechanical spring to allow additional force to be built up prior to the release of that force in either an up or a down jar. Compounders are useful additions with, for example, a coiled tubing jarring operation, because they allow additional force to be built up and stored in the compounder to be transferred during a jar, without imposing additional strain on the already limited compressive and tensile stress of the tubing string itself. 
     The double-acting compounder disclosed herein may be used with coiled tubing. Adapting such a tool to a coiled tubing application presents some challenges to overcome. A coiled tubing operation may involve, for example, the use of a single continuous pipe or tubing. The tubing, which is coiled onto a reel and uncoiled as it is lowered into the well bore, can be used for, for example, drilling or workover applications. However, coiled tubing presents a number of working constraints to existing tool design. First of all, due to the limited size of the coiled tubing, limited compressive loads can be placed on the tubing by the rig operator. Essentially, this means that downhole tools which require compressive force to operate, such as a jarring tool, must be capable of operating with the limited compressive load capability of coiled tubing. In addition, in coiled tubing application the overall length of the downhole tool becomes significant since there is limited distance available between the stuffing box and the blowout preventor to accommodate the bottom hole assembly. A typical bottom hole assembly may include, for example, a quick disconnect, a sinker bar located below the quick disconnect to provide weight to the bottom hole assembly, the jar, a release tool below that of some type, and then an overshot. Other tools may also be present, as required. Thus, the length of any tool used itself becomes particularly significant since the entire bottom hole assembly may be required to fit within the limited distance between the stuffing box and blowout preventor to introduce it into a pressurized well. Furthermore, within these confines, the compounder may be required to have a large enough internal bore to permit pump-down tools to pass. Thus, the coiled-tubing compounder may have a limited overall wall thickness in view of limited outer diameter conditions. 
     As in the case with conventional drill pipe, coiled tubing or other down hole tools, these items may get stuck in the well bore at times. Under these circumstances, repetitive upjarring or downjarring with a jarring tool may be useful. Many traditional double-acting jar tools do not perform this function, as upon resetting from a jar in one direction, only a jar in the opposite direction may be subsequently enacted. The double acting compounder disclosed herein allows a user to enhance the jarring force for a jar in either direction. Further, the double-acting compounder disclosed herein allows a user to subsequently repetitively jar in either direction. In some embodiments this compounder design may be adapted for use in a conventional drill string as well. 
     Referring to  FIGS. 3A-C , a double-acting compounder  10  is illustrated comprising a first end  12 , a second end  14 , an outer housing  16 , an upper mandrel  18 , and a lower mandrel  20 . Outer housing  16  defines first end  12  of compounder  10 . Upper mandrel  18  is at least partially disposed telescopically within outer housing  16  to define an uphole fluid chamber  22  between upper mandrel  18  and outer housing  16 . Upper mandrel  18  defines second end  14 . First and second ends  12  and  14  refer to relative ends of compounder  10 , and do not imply that one end must always be oriented downhole of the other end. In some embodiments, first end  12  may be connected, directly or indirectly, to a tubing string (not shown), while second end  14  is connected, directly or indirectly, to a jarring tool (not shown). In other embodiments, this orientation is reversed. A skilled worker would understand that compounder  10  could be oriented upside down in a well, and could still carry out the function of the compounder. 
     Lower mandrel  20  is at least partially disposed telescopically within outer housing  16  to define a downhole fluid chamber  24  between lower mandrel  20  and outer housing  16 . In some embodiments, lower mandrel  20  is disposed entirely within outer housing  16 . Uphole fluid chamber  22  and downhole fluid chamber  24  each contain fluid, have a variable stroke-dependent volume, and are sealed at uphole ends  26 ,  30 , and downhole ends  28 ,  32 , respectively. Variable stroke-dependent volume refers to the fact that, for example, due to the respective dimensions of upper mandrel  18  and outer housing  16  that define uphole fluid chamber  22 , relative longitudinal movement between upper mandrel  18  and outer housing  16  acts to increase the volume of uphole fluid chamber  22  in one direction, and decrease the volume in the other direction. Similarly, due to the respective dimensions of lower mandrel  20  and outer housing  16  that define downhole fluid chamber  24 , relative longitudinal movement between lower mandrel  20  and outer housing  16  acts to increase the volume of downhole fluid chamber  24  in one direction, and decrease the volume in the other direction. This way, motion in one direction will expand the volume, and thus the fluid contained within, and motion in the other direction will compress the volume and thus the fluid contained within. Energy may be stored in chambers  22  and  24  during either expansive or compressive movements. The fluid contained within uphole and downhole fluid chambers  22  and  24  may be, for example, hydraulic fluid. In some embodiments, the fluid may be compressible, for example compressible hydraulic liquid. The fluid creates a fluid spring within chambers  22  and  24 , in which the jar compounding energy may be stored to enhance the jarring impact. A floating seal  25  may be present at least one of uphole end  26 ,  30  and downhole end  28 ,  32  of at least one of uphole fluid chamber  22  and downhole fluid chamber  24 . In some embodiments, uphole fluid chamber  22  may comprise floating seal  25  at least one of uphole and downhole ends  26  and  28 , respectively. Downhole fluid chamber  24  may comprise floating seal  25  ( FIGS. 3A-C ),  25 A,  25 B,  25 C ( FIGS. 8-9 ) at least one of uphole and downhole ends  30  and  32 , respectively. Floating seal  25  allows pressure differentials between either or both of chambers  22  and  24  and outside of compounder  10  to equalize. This may prevent, for example, either or both of chambers  22  and  24  from collapsing under the extreme fluid pressures that may be experienced downhole. Either or both of chambers  22  and  24  may be annular in shape. In some embodiments, there may be one or more of either or both chambers  22  and  24  (plural fluid chambers), each one operating according to the embodiments disclosed herein for compounding operation. At least one of upper mandrel  18 , lower mandrel  20 , and outer housing  16  may be individually composed of, for example, one or more units connected together. Each unit may be, for example, threadably connected together as is well known in the art, and as is illustrated in the figures. At least one of outer housing  16 , upper mandrel  18 , and lower mandrel  20  may be, for example, tubulars. 
     Upper mandrel  18  has a first shoulder  34  engagable with and facing a second shoulder  36  of lower mandrel  20  to move lower mandrel  20  during at least a portion of a stroke. Referring to  FIGS. 1A-C , in some embodiments, first shoulder  34  is downhole facing, second shoulder  36  is uphole facing, and first shoulder  34  is engagable with second shoulder  36  to move lower mandrel  20  during at least a portion of a downstroke. The sequence from  FIGS. 3A-C  to  1 A-C illustrates an embodiment where this occurs. In other embodiments, first shoulder  34  may be uphole facing, second shoulder  36  may be downhole facing, and first shoulder  34  is engagable with second shoulder  36  to move lower mandrel  20  during at least a portion of an upstroke. Referring to  FIG. 4 , in some embodiments, upper mandrel  18  further comprises an uphole facing shoulder  38  engagable with and facing a downhole facing shoulder  40  of lower mandrel  20  to move lower mandrel  20  during at least a portion of the upstroke. 
     Referring to  FIGS. 3A-C , compounder  10  may further comprise an alignment spline  42  between upper mandrel  18  and outer housing  16 . In some embodiments, compounder  10  may further comprise an alignment spline (not shown) between lower mandrel  20  and outer housing  16 . The alignment splines aid to restrict any relative axial rotation between mandrels  18 ,  20 , and outer housing  16 . 
     Referring to  FIGS. 3A-C , compounder  10  may further comprise restriction shoulders  46  and  48  in downhole fluid chamber  24  on lower mandrel  20  and outer housing  16 , respectively. Restriction shoulders  46 ,  48  are configured to face one another and collide to restrict the longitudinal movement of lower mandrel  20  within outer housing  16 . Referring to  FIGS. 3A-C , restriction shoulders  46 ,  48  are facing one another to collide and restrict the longitudinal upward movement of lower mandrel  20  within outer housing  16 . This prevents lower mandrel  20  from moving upward past a predefined point into an upstroke. In some embodiments, restriction shoulders  46 ,  48  face one another to collide and restrict the longitudinal downward movement of lower mandrel  18  within outer housing  16 . In other embodiments, there may be more than one set of restriction shoulders. In some embodiments, at least one set of restriction shoulders restricts longitudinal downward movement of lower mandrel  18  within outer housing  16 , and at least one other set of restriction shoulders restricts longitudinal upward movement of lower mandrel  18  within outer housing  16 . 
     Uphole fluid chamber  22  may be configured to increase or decrease in volume during downward movement relative to outer housing  16 . Similarly, downhole fluid chamber  24  may be configured to increase or decrease in volume during downward movement relative to outer housing  16 . In some embodiments, if the volume of one of chambers  22  or  24  is configured to expand during a downstroke, the volume of the other of chambers  22  or  24  will be configured to compress during a downstroke. This way, when upper mandrel  18  is in the process of moving lower mandrel  20 , a down enhancement may be achieved. Due to the extreme pressures experienced downhole, the larger the reduction of pressure within a sealed chamber, the greater the pressure differential between the chamber and outside the compounder  10 , and hence the greater the likelihood that compounder  10  may be crushed. In some embodiments, first shoulder  34  is engagable with second shoulder  36  to move lower mandrel  20  during at least a portion of a downstroke. In this embodiment, downhole fluid chamber  24  may be configured to decrease in volume during a downstroke, in order to create the downstroke compounding force by a combination of the expansion of fluid in uphole fluid chamber  22  and the compression of fluid in downhole fluid chamber  24 , although the contribution from the expansion of chamber  22  is relatively small. This way, uphole fluid chamber  22  will be configured to decrease in volume during upward movement relative to outer housing. Thus, an up enhancement may be achieved by upward movement of upper mandrel  18  relative to outer housing  20 , and a downstroke enhancement may be achieved by a combined downward movement of upper mandrel  18  and lower mandrel  20  relative to outer housing  16 . 
     Referring to  FIGS. 3A-C , there are numerous ways in which either or both of chambers  22 ,  24  may be configured to have a variable stroke-dependent volume. For the purposes of this illustration, reference will be made to uphole fluid chamber  22 , although it should be understood that downhole fluid chamber  24  contains the same elements, and functions under the same principles. Compounder  10  may have a longitudinal axis  50 . Referring to  FIGS. 3A-C  and  5 , a first sealing interface  52  may be defined between upper mandrel  18  and outer housing  16  at uphole end  26 . Referring to  FIG. 5 , first sealing interface  52  may have a first cross-sectional area A defined between the first sealing interface  52  and the longitudinal axis  50 . A second sealing interface  54  may be defined between upper mandrel  18  and outer housing  16  at downhole end  28 . Second sealing interface  54  may have a second cross-sectional area B defined between second sealing interface  54  and the longitudinal axis  50 . In an annular chamber, areas A and B may be the area of a circle defined by interfaces  52  and  54 , respectively as illustrated. Sealing interfaces  52  and  54  are defined as the interface between upper mandrel  18  and outer housing  16  across which a portion of upper mandrel  18  is able to sealably cross during axial motion relative to outer housing  16 . Because these interfaces need not be defined along a transverse cross section at either end, areas A and B need not be defined along an exact transverse cross-section at either end. Rather, they should be defined as the area of a projection of the respective sealing interfaces onto a transverse cross section. Referring to  FIG. 5 , if first and second cross-sectional areas A and B are different from one another, then relative movement between upper mandrel  18  and outer housing  16  will change the volume of uphole fluid chamber  22 . In the embodiment illustrated in  FIG. 5 , assuming that second sealing interface  54  is positioned into and underneath the page, and first sealing interface  52  is positioned on the page, movement of upper mandrel  18  into the page relative to outer housing  16  will increase the volume of uphole fluid chamber  22 , since area B is larger than area A. Referring to  FIG. 6 , a similar interface to interface relationship is illustrated with a non-annular fluid chamber  22 . Because area A is larger than B, movement of upper mandrel  18  into the page relative to outer housing  16  will decrease the volume of uphole fluid chamber  22 . 
     The operation of one embodiment of compounder  10  will now be described. Referring to  FIGS. 3A-C , compounder  10  is positioned in a neutral position. Compounder  10 , in this scenario, will be understood to be connected to a tubing string in association with a double-acting jarring tool. If a user wishes to carry out an upjar, a tensile force is introduced on the tubing string. Referring to  FIGS. 2A-C , upper mandrel  18  is drawn upwards relative to outer housing  16 . Because cross-sectional area B at downhole end  28  is larger than cross-sectional area A at uphole end  26 , the volume of uphole fluid chamber  22  is reduced, compressing the fluid contained within. This compression of chamber  22  stores tensile energy, and as the jar used in association with compounder  10  clears the restriction and moves to upjar, the tension between outer housing  16  and the jar is reduced, allowing outer housing  16  to move upward relative to upper mandrel  18 , releasing the energy stored in fluid chamber  22  into the tubing string, and thus into the upstroke. Referring to  FIGS. 3A-c , after the upstroke, upper mandrel  18  is biased back into a neutral position by the fluid contained within uphole fluid chamber  22 . If a user wishes to carry out a downjar, compression is introduced into the tubing string. Referring to  FIGS. 1A-C , under compression, due to compressive force between outer housing  16  and the jar, upper mandrel  18  is moved downward relative to outer housing  16 . As upper mandrel  18  is moved downward, the volume of uphole fluid chamber  22  is increased, expanding any fluid contained within, and storing energy in the fluid. First shoulder  34  contacts second shoulder  36  of lower mandrel  20 , and lower mandrel  20  begins to move downward relative to outer housing  16  along with upper mandrel  18 . Because cross-sectional area B of downhole end  32  is smaller than cross-sectional area A of uphole end  30  (both areas A and B now referring to downhole fluid chamber  24 ), as lower mandrel  16  moves downward relative to outer housing  16 , the volume of downhole fluid chamber  24  is reduced, compressing the fluid contained within and storing compressive energy inside the fluid. As soon as the jar clears the restricted movement portion, and moves rapidly to downjar, the tension between outer housing  16  and the jar is released, effectively allowing outer housing  16  to move downward relative to lower mandrel  20  and upper mandrel  18  back to neutral. Upon this downward movement, the energy stored within chambers  22  and  24  is released into the jar to enhance the impact of the downjar. 
     Compounder  10  of the type disclosed herein may be used in, for example, fishing operations, drilling operations, coiled tubing, and drill strings. The use of up or down in this document illustrates relative motions within compounder  10 , and are not intended to be limited to vertical motions, or upward and downward motions. It should be understood that compounder  10  may be used in any type of well, including, for example, vertical, deviated, and horizontal wells. 
     In the claims, the word “comprising” is used in its inclusive sense and does not exclude other elements being present. The indefinite article “a” before a claim feature does not exclude more than one of the feature being present. Each one of the individual features described here may be used in one or more embodiments and is not, by virtue only of being described here, to be construed as essential to all embodiments as defined by the claims.