Abstract:
A downhole swivel joint assembly comprising an upper component and a lower component. The components may assume either of two stable positions relative to each other, namely an unactivated configuration in which the components are rotationally fast with each other by virtue of the inter-engagement of splines of the lower component with splines of the upper component and an activated configuration in which the respective splines are disengaged so that the upper and lower components can rotate relative to each other. In the activated configuration the upper component is supported relative to the lower component on a ball bearing pack. Movement of the components between the activated and unactivated configurations is controlled by a resiliently deformable latch member which is C-shaped in transverse cross-section. The latch member has an internal profile which co-operates with an external profile provided on the upper component mandrel to allow the upper and lower components to snap between the activated and unactivated configurations.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the invention 
     The present invention relates to a downhole swivel joint assembly and to a method of using said swivel joint assembly and furthermore to a wellbore clean-up assembly comprising said downhole swivel joint assembly and to a method of using said clean-up assembly. 
     2. The prior art 
     It is known in the gas and oil drilling industries to use a swivel joint assembly in wellbore clean-up operations to allow an uphole section of drill string to be rotated whilst a connected downhole section of string remains stationary. In these prior art swivel joint assemblies, a shear ring/pin arrangement is provided for allowing release of the assembly from an unactivated configuration, in which the uphole and downhole sections are locked to one another, and an activated configuration, in which the components are permitted to rotate relative to one another. It will be understood however that, once the shear ring/pin has sheared so as to allow movement from the unactivated configuration to the activated configuration, the assembly cannot then be retained in the unactivated configuration with the same effectiveness. The prior art swivel joint assemblies are arranged so that, when they are tripped uphole after having been activated, they will return to the unactivated configuration. However, with the primary means for retaining the assembly in the unactivated configuration no longer in place, subsequent movement of the assembly in a downhole direction and in a high wellbore drag environment (as encountered in high angle and horizontal wellbores) will frequently result in the assembly undesirably moving to the activated configuration. This is due to wellbore drag resisting movement of the assembly in a similar way to a landing profile provided within a wellbore for the purpose of activating an assembly. With the assembly arranged in an activated configuration as it is being run downhole, it is not possible for the downhole section to be rotated and this can be a disadvantage in certain operations. Furthermore, the prior art swivel joint assemblies used in clean-up operations incorporate vent apertures which are opened in moving from the unactivated configuration to the activated configuration and then allow cleaning fluid to be ejected from the interior of the assembly onto the wellbore casing to be cleaned. However, the vent apertures cannot be opened independently of the uncoupling of the uphole and downhole sections of the swivel joint assembly. This can be restrictive in certain clean-up operations. Prior art swivel joint assemblies also have poor rotational speed and load bearing performance which the applicant believes is due to their use of thrust plates as a bearing mechanism. 
     It is an object of the present invention to provide an improved downhole swivel joint assembly and wellbore clean-up assembly. 
     It is also an object of the present invention to provide an improved method of cleaning a wellbore. 
     SUMMARY OF THE INVENTION 
     A first aspect of the present invention provides a downhole swivel joint assembly comprising first and second components movable relative to one another in an axial direction along a longitudinal axis of the assembly, said components being movable relative to one another in said axial direction between an unactivated configuration, in which relative rotational movement between the first and second components is prevented, and an activated configuration, in which said rotational movement is permitted; wherein the assembly further comprises means for resisting movement of said components from the unactivated configuration to the activated configuration, said means comprising a resiliently deformable member arranged so as to be resiliently deformed when said components are moved from the unactivated configuration to the activated configuration. 
     Thus, in moving from the unactivated configuration to the activated configuration, the resisting means must be resiliently deformed and, since said resisting means is resilient to said deformation, it will be understood that said means is elastically deformed and will therefore apply a force which tends to resist the movement of said components. It will be understood that the resisting means may simply be a gripping member which relies on friction forces to resist movement. In this arrangement, when in the unactivated configuration, the resisting means may be resiliently deformed so as to apply a gripping force to one of said components and, by virtue of friction forces, provide resistance to movement. 
     In an alternative arrangement, said resiliently deformable member may comprise a first cam surface and may be retained in a fixed axial position relative to one of said first and second components, the other one of said components being provided with a second cam surface for co-operating with the first cam surface and radially camming said member into a resiliently deformed position when moving from the unactivated configuration. 
     Preferably, said resiliently deformable member comprises a third cam surface, said other one of said components being provided with a fourth cam surface for co-operating with the third cam surface and radially camming said member into a resiliently deformed position when moving from the activated configuration. It is also desirable for said resiliently deformable member to comprise a cylindrical wall having a slot extending through the full thickness of the wall and along the full length of the cylindrical wall. The cylindrical wall may also be located about one of said first and second components. 
     Furthermore, the first component is ideally provided with means for connecting the assembly to further downhole equipment located, in use, above the assembly; and wherein the second component is provided with means for connecting the assembly to yet further downhole equipment located, in use, below the assembly. 
     The second component, or equipment connected thereto, may be provided with an arm member extending outwardly for engaging, in use, with an uphole facing shoulder within a wellbore. The uphole facing shoulder may be the top of a liner hanger. 
     A bearing comprising rolling elements is ideally provided between the first and second components so as to assist in relative rotation between said components when said components are in the activated configuration. The bearing may comprise a plurality of races. Furthermore, the bearing may be located so as to be spaced from one of said components when said components are in the activated position. Said spaced component is ideally provided with means for engaging, when said components are in the activated configuration, co-operating means provided on the bearing so as to prevent relative rotation between the engaged parts of said component and bearing. 
     It will be understood that the resiliently deformable member allows said components of the swivel joint assembly to be repeatedly moved back and forth between the unactivated and activated configurations without loss of effectiveness at retaining the swivel joint assembly in the unactivated configuration. A swivel joint assembly according to the present invention may therefore be returned to the unactivated configuration and pulled uphole, and then subsequently tripped back downhole in a high drag environment without a likelihood of the assembly becoming activated. 
     A second aspect of the present invention provides a wellbore clean-up assembly comprising a downhole swivel joint assembly as referred to above and further comprising a fluid circulating assembly, the fluid circulating assembly comprising a body incorporating a wall provided with at least one vent aperture extending therethrough; and a piston member slidably mounted in the body and slidable in the body in response to the application thereto of fluid pressure; wherein the piston member is slidable between a first position relative to the body, in which the or each vent aperture is closed, and a second position relative to the body, in which the or each vent aperture is open; the fluid circulating assembly further comprising constraining means adapted to prevent movement of the piston member from the first position to the second position; and overriding means for overriding the contraining means so as to permit movement of the piston member to the second position. 
     The piston may be biased to the first position by means of a spring. Furthermore, the piston member may incorporate a wall provided with at least one opening extending therethrough such that, in the second position the opening of the piston member and the body are in register, and in the first position the openings of the piston member and the body are out of register. Preferably, the constraining means may comprise a guide pin and a guide slot for receiving the guide pin. The guide slot may extend in a direction having one component parallel to the direction of axial movement of the piston member. The overriding means may comprise an extension of the guide slot. Also, the guide pin may be fixedly located relative to the body and the guide slot may be formed in the exterior surface of the piston member or the second piston member slidably mounted in the body. 
     A further aspect of the present invention provides a method of cleaning a wellbore, the method comprising the steps of making up downhole apparatus comprising the wellbore clean-up assembly as referred to above; running said assembly down a wellbore to be cleaned; landing the downhole swivel joint on a restriction within the wellbore; applying weight of the downhole apparatus to said restriction so as to move the downhole swivel joint from an unactivated configuration to an activated configuration; moving the piston member of the fluid circulating assembly from the first position to the second position; and ejecting fluid from the interior of the fluid circulating assembly through the or each vent aperture. 
     The method may further comprise the step of pumping cleaning fluid down the interior of the downhole apparatus and up the annulus between said apparatus and the wellbore prior to moving the piston member of the fluid circulating assembly. 
     In addition, the method may comprise the step of making up said downhole apparatus so that the fluid circulating assembly is located uphole of the downhole swivel joint assembly; and rotating the fluid circulating assembly within the wellbore once the swivel joint assembly has been activated. The step of rotating the fluid circulating assembly comprises the step of rotating a conveying string connected to the fluid circulating assembly. Ideally, the conveying string is rotated from an uphole end of the wellbore. 
    
    
     
       Embodiments of the present invention will now be described with reference to the accompanying drawings. 
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic side view of a downhole assembly, according to the present invention, located within a borehole; 
         FIG. 2  is a detailed cross-sectional side view of a downhole assembly, according to the present invention, located downhole in an unactivated configuration; 
         FIG. 3  is a detailed cross-sectional side view of a downhole assembly, according to the present invention, located downhole in an activated configuration; 
         FIG. 4  is an end view of a C-ring latch member of the assembly shown in  FIGS. 2 and 3 ; 
         FIG. 5  is a cross-sectional side view of the C-ring member of  FIG. 4  taken along line A-A of  FIG. 4 ; 
         FIG. 6  is a perspective view of the C-ring member of  FIGS. 4 and 5 ; 
         FIG. 7  is a partial view, in cross-section, of a modified version of the assembly shown in  FIGS. 2 and 3 ; 
         FIG. 8  is a cross-sectional view of the assembly of  FIG. 7  taken along line B-B of  FIG. 7 ; 
         FIG. 9  is an enlarged detailed cross-sectional side view of the downhole assembly shown in  FIGS. 2 and 3  modified so as to incorporate an alternative latch mechanism, wherein the assembly is located downhole in an unactivated configuration; 
         FIG. 10  is an enlarged detailed cross-sectional side view of the downhole assembly shown in  FIG. 9 , wherein the assembly is located downhole in an activated configuration; 
         FIG. 11  is a cross-sectional side view of a circulating sub arranged in a first closed configuration with downhole movement of a sleeve restricted by a control groove and pin; 
         FIG. 11   a  is a plan view of the unwrapped profile of a control groove located relative to a control pin as shown in  FIG. 11 ; 
         FIG. 12  is a cross-sectional side view of the circulating sub arranged in a second closed configuration with downhole movement of the sleeve restricted by the control groove and pin, and with the angular position of the sleeve differing to that shown in  FIG. 11 ; 
         FIG. 13  is a cross-sectional side view of the circulating sub arranged in an open configuration; 
         FIG. 13   a  is a cross-sectional view taken along line  13   a - 13   a  of  FIG. 13 ; and 
         FIG. 14  is a cross-sectional side view of the circulating sub arranged in an emergency closed configuration. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     A downhole assembly  2  according to the present invention is schematically shown in  FIG. 1  of the accompanying drawings. The assembly  2  functions to scrape and clean the casing of a wellbore during a downhole clean-up operation. To this end, the downhole assembly  2  comprises an upper brush/scraper assembly  4  comprising brushes  6  and scrapers  8  for engaging with a 9⅝ inch wellbore casing  10 . Downhole of the upper brush/scraper assembly  4 , the downhole assembly  2  comprises a multi-cycle circulating sub  12  having vent apertures  14  through which cleaning fluid may pass from a longitudinal bore (not shown in  FIG. 1 ), running through the assembly  2 , to the exterior of the downhole assembly  2 . Thus, during use of the downhole assembly  2 , the multi-cycle circulating sub  12  may, through an appropriate repeated application of fluid pressure, be cycled between open and closed configurations in which the vent apertures  14  are themselves open or closed. With the vent apertures  14  open (the open configuration), cleaning fluid may be ejected into the annulus  16  between the 9⅝ inch wellbore casing  10  and the downhole assembly  2 . The presence of the cleaning fluid in the annulus  16  assists in the clean-up operation. Suitable multi-cycle circulating subs for use in the downhole assembly  2  is described in GB 2 314 106 and GB 2 377 234, the disclosures of which are incorporated herein by reference. However, for the reader&#39;s ease of reference, one of the circulating subs disclosed in GB 2 377 234 will now be described below. 
     A circulating sub  12  is shown in  FIGS. 11 to 14  of the accompanying drawings. The sub  12  is a six-cycle circulating sub wherein the arrangement of the downhole portions of a second body member  208 , sleeve  226  and piston  242  is such that, when the piston is in a closed position as shown in  FIGS. 11 and 12  (or an emergency closed position as shown in  FIG. 14 ), wellbore fluid may flow through the interior of the circulating sub  12 ; however when the piston  242  is in an open position as shown in  FIG. 13 , the bore  11  through the circulating sub  12  is closed and all wellbore fluid flowing downhole through the circulating sub  12  is directed into the annulus through vent apertures  14 . 
     More specifically, the downhole portions of the sleeve  226  and piston  242  are arranged with an asymmetric configuration. The piston  242  defines a piston bore  258  having an upper portion coaxially arranged with the longitudinal axis of the circulating sub  12  and a lower portion located downhole of piston flow ports  172  which extends downhole at an angle relative to the longitudinal axis of the circulating sub  12 . Accordingly, the downhole end of the piston bore  258  opens at a location offset from the longitudinal axis of the apparatus  12 . This offset location provides a downhole facing piston shoulder  259  extending inwardly into the bore  11  of the circulating sub  12 . A single piston element  276  extends downwardly from the shoulder  259 . The downhole end of the sleeve  226  has a reduced diameter defining a restricted bore  227  within an axis offset relative to the longitudinal axis of the circulating sub  12 . Uphole of the reduced diameter, the sleeve  226  is provided with four ports  229  which extend radially through the thickness of the sleeve  226 . 
     When in the closed configuration as shown in  FIGS. 11 and 12  wellbore fluid may flow through the circulating sub  12  via the piston bore  258 , about the downwardly facing piston shoulder  259  and through the restricted sleeve bore  227 . In  FIG. 11 , the circulating sub  12  is shown with the piston  242  displaced downhole against the bias of a compression spring  144  by means of an appropriate flow rate of wellbore fluid. Displacement of the piston  242  into an open position is prevented by abutment of the piston element  276  against a single sleeve element  232  defining the restricted bore  227 . The circulating sub  12  is shown in  FIG. 12  cycled to a further closed configuration with the piston  242  having been rotated within a second body member  208 . Again, movement of the piston  242  into the open position is prevented by abutment of the piston element  276  against the sleeve element  232 . However, with the circulating sub  12  cycled to the configuration shown in  FIGS. 13 and 13   a , it will be seen that the piston  242  has rotated sufficiently for the piston element  276  to align with the restricted bore  227  (acting as a sleeve slot) allowing the piston  242  to move further downhole relative to the sleeve  226 . In so doing, the piston flow ports  172  align with the vent apertures  14  (allowing flow to the annulus) and the downwardly facing piston shoulder  259  closes the restricted sleeve bore  227  (preventing fluid flow within the bore  11  downhole past the second body member  208 ). Fluid flow through the four ports  229  is not possible in the open and closed piston positions of  FIGS. 11 ,  12 ,  13  and  13   a  due to the sealing of these ports by means of the second body member  208 . 
     The circulating sub  12  may be moved to an emergency closed position in the event that the piston  242  becomes jammed and the biasing force of the compression spring  44  is insufficient to return the piston  242  to its original uphole position in abutment with a first body member  5 . The emergency closed configuration is achieved by increasing the flow of fluid through the bore  11 . The flow rate is increased until the downhole force applied to the piston  242  is sufficient to release the piston  242  and shear a shear pin  29  holding the sleeve  226  relative to the sub body. The piston  242  and sleeve  226  are then moved downhole. Downhole movement of the piston  242  and sleeve  226  is limited by abutment of the sleeve  226  with a third body member  9 . Although the restricted sleeve bore  227  remains sealed by the downwardly facing piston shoulder  259 , flow through the bore  11  into the third body member  9  is permitted by means of the ports  229  provided in the sleeve  226 . Flow through the ports  229  is possible with the sleeve  226  abutting the third body member  9  by virtue of a circumferential recess  231  provided in the interior surface of the second body member  208  at a downhole portion thereof. More specifically, the recess  231  is located uphole of the third body member  10  and downhole of the four ports  229  when the sleeve  226  is located in a non-emergency position (ie when retained by the shear pin  29  as shown in  FIGS. 11 to 13   a ). The circumferential recess  231  has sufficient downhole length for wellbore fluid to flow through the sleeve ports  229 , around and beneath the sleeve element  232 , and into the third body member  9 . 
     The downhole assembly  2  further comprises a swivel joint assembly  18  located downhole of the multi-cycle circulating sub  12 . The purpose of the swivel joint assembly  18  is to allow selective relative rotation between components of the assembly  2  located uphole and downhole of the swivel joint assembly  18 . The swivel joint assembly  18  is weight activated inasmuch as the swivel joint assembly  18  may be arranged to prevent relative rotation of the aforementioned component until the assembly  18  is received on a shoulder (for example, a tie-back receptacle, TBR) and at least some of the weight of the assembly  2  located above the swivel joint assembly  18  is applied. On the application of this weight, the swivel joint assembly  18  is activated so as to allow relative rotation between upper and lower components  18   a , 18   b  of the swivel joint assembly  18  and components of the downhole assembly  2  connected thereto. The detailed design of the swivel joint assembly  18  is discussed below with reference to  FIGS. 2 to 10  of the accompanying drawings. 
     Having regard to  FIG. 1 , it will be seen that the downhole assembly  2  further comprises a lower brush/scraper assembly  20  located downhole of the swivel joint assembly  18 . The lower brush/scraper assembly  20  comprises brushes  22  and scrapers  24  for engaging with a 7 inch wellbore casing  26 . 
     In a downhole clean-up operation, the downhole assembly  2  is tripped in hole with the swivel joint assembly  18  arranged in an unactivated configuration wherein the upper and lower components  18   a , 18   b  of the swivel joint assembly  18  are rotatively locked to one another. Thus, rotation of the conveying string to which the upper brush/scraper assembly  4  is connected will result in a rotation of the lower brush/scraper assembly  20 . Torque may therefore be transmitted through the downhole assembly  2  (including the swivel joint assembly  18 ) and allow both upper and lower brush/scraper assemblies  4 ,  20  to be used in cleaning wellbore casing. The provision of the weight activated swivel joint assembly  18  renders the downhole assembly  2  particularly suitable for use in a wellbore where an uphole facing shoulder is present. A typical scenario where this generally occurs is at a point of reduction in wellbore diameter. For example, in the schematic view of  FIG. 1 , a 9⅝ inch casing  10  reduces to a 7 inch casing  26 . The upper and lower brush/scraper assemblies  4 ,  20  are appropriately sized so as to engage the 9⅝ inch and 7 inch casings  10 ,  26  respectively in the region of the reduction in bore diameter. With the lower brush/scraper assembly  20  located in the 7 inch casing  26 , the conveying string (not shown) may be used to move the downhole assembly  2  axially in uphole and downhole directions within the wellbore. The conveying string may also be used to rotate the downhole assembly  2  (and, consequently, the upper and lower brush/scraper assemblies  4 ,  20 ) so as to clean both the 9⅝ inch and 7 inch casings  10 ,  26 . 
     After the scraping and brushing operation has been completed, wellbore fluid is replaced with an appropriate cleaning fluid such as brine or sea water. Normally, the cleaning fluid is pumped downhole through an internal longitudinal bore running through the conveying string and downhole assembly  2 . The cleaning fluid is ejected from the downhole end of the assembly  2  and passes uphole through the annulus between the assembly  2  and the 9⅝ inch and 7 inch casings  10 ,  26 . This process is completed with the vent apertures  14  closed. However, once the cleaning fluid rises up the annulus beyond the vent apertures  14 , the multi-cycle circulating sub  12  is cycled by an appropriate repeated variation in fluid/pressure flow within the downhole assembly  2  so as to open the vent apertures  14 . The cleaning fluid passing downhole through the longitudinal bore of the downhole assembly  2  is then able to eject through the vent apertures  14  and forcefully engage the 9⅝ inch casing  10  so as to assist in the cleaning and general removal of debris from the surface of the casing  10 . Furthermore, it will be understood that the fluid ejected through the vent apertures  14  increases the general rate of fluid flow in the annulus and thereby assists the cleaning operation. 
     In a variation of this process, a reverse circulation takes place before the conventional pumping from the surface down the string so as to effect fluid replacement. The multi-cycle circulating sub  12  will remain closed during the reverse circulation. 
     Typically, the cleaning fluid will be pumped downhole behind pill and spacer fluid. The pill fluid is a high density drilling mud (considerably more dense than the wellbore drilling mud) and is pumped downhole ahead of the spacer fluid to drive mud/debris in the wellbore annulus uphole and to stop debris settling out. The spacer fluid follows behind the pill fluid and ahead of the cleaning fluid. For an oil base wellbore mud fluid, the spacer fluid will be pure base oil. 
     In order to further improve the cleaning process (by swirling annulus mud more vigorously so as to prevent solids from settling out), the circulating sub  12  can be configured with the vent apertures open so that some of the fluid flowing downhole through the apparatus is directed through said apertures into the 9⅝ inch casing annulus. If the design of the circulating sub permits, all fluid flow may be directed through the vent apertures. In either case, the brushes and scrapers in the 7 inch casing will then operate in a drier environment, which may not be desirable. However, this can be avoided by activating the swivel joint assembly  18  and, in so doing, uncoupling the lower brush/scraper assembly  20  from the remaining assembly and conveying string located uphole thereof. In order to activate the swivel joint assembly  18 , the assembly  18  is lowered onto the uphole facing shoulder resulting from the transition from the 9⅝ inch casing  10  to the 7 inch casing  26 . In practice, a tie-back receptacle  28  will generally be located in the 9⅝ inch casing  10  adjacent the reduction in borehole diameter and it is with this receptacle  28  that the swivel joint assembly  18  engages. Once engaged with the tie-back receptacle  28 , further downhole movement of the lower component  18   b  of the swivel joint assembly  18  is prevented and the weight of the downhole assembly  2  and conveying string may be increasingly applied to the 7 inch wellbore casing. As will be appreciated from the subsequent detailed description, the swivel joint assembly  18  comprises a latch mechanism which operates to uncouple the upper and lower components  18   a , 18   b  of the assembly  18  and thereby allow relative rotation of said components  18   a , 18   b  once a predetermined weight has been applied to the tie-back receptacle  28 . This uncoupling is accompanied by a small downhole movement of the upper component  18   a  and the remainder of the assembly  2  and conveying string located thereabove. This small downhole axial movement is indicative to an operator at the surface that the swivel joint assembly  18  has been activated. More specifically, the weight of the lower component  18   b  and equipment connected downhole thereof will be supported in the 7 inch casing and come off at the surface. Thereafter, when additional load is applied (eg 30,000 to 60,000 lbs), the upper component  18   a  will move downhole accompanied by a corresponding movement at the surface indicating decoupling. 
     With the swivel joint assembly  18  activated, the upper brush/scraper assembly  4  may be more readily rotated at a greater speed than if the assembly below the swivel joint assembly  18  was also to be rotated. Indeed, the upper brush/scraper assembly  4  may typically be rotated at the maximum rotational speed (for example, 250 rpm) whilst the lower brush/scraper assembly  20  remains stationary. This high rotational speed of the upper brush/scraper assembly  4  results in greater turbulence within the annulus and allows solids in the annulus to be entrained more effectively in the uphole flow of annulus fluid. Cleaning efficiency within the 9⅝ inch casing  10  is thereby improved. Also, the use of a bearing assembly (see below) assists in the upper section being rotated at higher speeds than in prior art systems which have used thrust plate arrangements. 
     A more detailed view of the swivel joint assembly  18  is shown in  FIGS. 2 and 3  of the accompanying drawings. In  FIG. 2 , the assembly  18  is shown in an unactivated configuration, whilst in  FIG. 3  the swivel joint assembly  18  is shown in an activated configuration. First, with reference to  FIG. 2 , it will be seen that the upper component  18   a  of the swivel joint assembly  18  comprises a stabiliser  30  having a plurality of radially extending blades  32  for engaging the 9⅝ inch casing  10  and retaining the swivel joint assembly  18  concentrically located therewithin. The upper component  18   a  of assembly  18  also comprises a mandrel  34  connected to the downhole end of the stabiliser  30 . The mandrel  34  is of an elongate cylindrical form and telescopically locates within the lower component  18   b  of the swivel joint assembly  18 . 
     The lower component  18   b  of the swivel joint assembly  18  comprises a landing sub  36  with radially extending arm members  38  projecting from a substantially cylindrical body. The arm members  38  are circumferentially spaced about the body of the landing sub  36  so that, when the arm members  38  bear against the tie-back receptacle  28  during use, annulus fluid may flow uphole past the landing sub  36  through the spaces between the arm members  38 . 
     The lower component  18   b  further comprises a bearing sub  40  connected to the uphole end of the landing sub  36 . The bearing sub  40  houses a multi-race ball bearing pack  42 . This ball bearing pack  42  is provided with upper and lower contact surfaces for each bearing race which are oriented at an angle of 45° to the longitudinal axis  44  of the swivel joint assembly  18 . The arrangement is such that the ball bearing pack  42  is capable of withstanding uphole and downhole axial loads of 50,000 lbs. Alternative types and arrangements of bearing pack will be apparent to a skilled reader. The uphole end of the ball bearing pack  42  is provided with castellations  46  which, when the swivel joint assembly  18  is activated, engage with corresponding castellations  48  provided on the downhole end of the mandrel  34 . It will be understood that, when the lower and upper castellations  46 ,  48  are engaged with one another, rotary motion of the mandrel  34  will be transmitted directly to the ball bearing pack  42 . In this way, the mandrel  34  may be rotated whilst the weight of the upper component  18   a  and associated conveying string is at least partially applied to the lower component  18   b  of the swivel joint assembly  18 . 
     The castellations  46  of the bearing pack  42  are provided on a shaft coupling  45  which is screw threadedly connected to the uphole end of a bearing shaft  47  running longitudinally through the inner races of the bearing sub  40 . The shaft coupling  45  presses down on a ring member  49  which, in turn, presses down on the inner bearing races and retains them located in relation to the bearing shaft  47 . 
     The ball bearing pack  42  is-retained in position within a bore of the bearing sub  40  by means of a ring member  50  which locates between and in abutment with an uphole end of the ball bearing pack  42  and a downhole end of a spline sub  52 . The spline sub  52  is threadedly connected to the bearing sub  40  and this threaded connection allows the ring  50  to be placed under compressive load and thereby ensure the ball bearing pack  42  is firmly retained in the desired axial position within the bore of the bearing sub  40 . The ring member  50  is selected to have a length suitable for ensuring the ball bearing pack  42  is pressed downhole. 
     The spline sub  52  is a generally elongate cylindrical member with a plurality of circumferentially spaced splines  54  projecting radially inwardly into a longitudinal bore of the spline sub  52  in which the mandrel  34  locates. The splines  54  are originally separate from the main body of the spline sub  52  and, during assembly of the swivel joint assembly  18 , are located through apertures in the body of the spline sub  52  and welded in position. The arrangement is such that, when the swivel joint assembly  18  is in the unactivated condition as shown in  FIG. 2 , the splines  54  engage with corresponding splines  56  which extend radially outwardly from the mandrel  34 . The upper and lower components  18   a , 18   b  of the swivel joint assembly  18  are thereby rotationally locked to one another. However, although the inter-engaging splines  54 ,  56  prevent relative rotation of the upper and lower components  18   a , 18   b  of the assembly  18 , the splines  54 ,  56  nevertheless do not hinder relative axial movement of said components  18   a , 18   b.    
     In order to assist in axial and rotational movement between the mandrel  34  and the spline sub  52 , a journal bearing  58  is located about the mandrel  34  downhole of the splines  54  of the spline sub  52 . Furthermore, in order to prevent a leakage of fluid from within the swivel joint assembly  18  to the wellbore annulus, a seal set  60  is provided between the mandrel  34  and the spline sub  52 . The seal set  60  is located about the mandrel  34  between and in engagement with the journal bearing  58  and a shoulder  62  inwardly projecting from the body of the spline sub  52  into the bore thereof. The seal  62  is preferably a static and rotational dual-directional chevron seal set. Whilst uphole movement of the journal bearing  58  and seal set  60  relative to the spline sub  52  is prevented by means of the shoulder  62 , downhole movement of these components  58 ,  60  is prevented by virtue of the journal bearing  58  being screw threadedly connected to the spline sub  52  with a left-hand screw thread. The journal bearing  58  is prevented from becoming unscrewed by means of a circlip  64  located downhole of the seal set  60  in a circumferential groove provided in the bore of the spline sub  52 . 
     In a preferred modified version of the spline sub  52 , retention of the splines of the spline sub in the required position is achieved without the need for welding. Such a modified spline sub  52 ′ is shown in  FIGS. 7 and 8  of the accompanying drawings. The splines  54 ′ of the modified spline sub  52 ′ are provided integrally with a cylindrical ring member  66  (see  FIG. 8 ) which locates between and in abutment with an uphole facing annular shoulder  68  defined in the bore of the spline sub  52 ′ body and a retaining cylindrical ring  70 . The ring  70  is itself prevented from moving uphole relative to the body of the spline sub  52 ′ by virtue of its abutment with a latch sub  80  (described hereinafter with reference to  FIGS. 2 and 3 ) screwthreadedly connected to the uphole end of the spline sub  52 ′. Thus, by means of this threaded connection, the cylindrical ring  70  is pressed onto the splined ring member  66  and thereby firmly retains said member  66  in axial position against the aforementioned uphole facing shoulder  68 . 
     In order to prevent rotational movement of the ring member  66  relative to the body of the modified spline sub  52 ′, the exterior surface of the ring member  66  is provided with two diametrically located straight slots  72  extending along the longitudinal length of the ring member  66 . In the assembled spline sub  52 ′, the slots  72  each receive a key  74  axially and rotationally fixed to the body of the spline sub  52 ′. The keys  74  thereby rotationally lock the ring member  66  to the body of the spline sub  52 ′. The keys  74  are themselves each located in an elongate slot provided in the body of the spline sub  52 ′ and, in the assembled spline sub  52 ′, are trapped between the body of the spline sub  52 ′ and the ring member  66  and are thereby retained in position. No welding of the keys  74  or the ring member  66  is required. 
     Returning to the apparatus of  FIGS. 2 and 3 , the lower component  18   b  of the swivel joint assembly  18  further comprises a latch sub  80  threadedly connected at its downhole end to the uphole end of the spline sub  52 . The latch sub  80  is of a generally cylindrical shape with an annular shoulder  82  projecting into a bore thereof and against which a C-ring latch member  84  abuts. As will be seen with particular reference to  FIGS. 4 and 6  of the accompanying drawings, the C-ring member  84  has a cylindrical shape with a straight slot  86  extending through the full thickness of the cylindrical wall of the member  84  and along the full length of the member  84  in a direction parallel with the longitudinal axis  88  of the member  84 . Furthermore, the internal surface of the C-ring latch member  84  is provided with three identical axially spaced circumferential ridges  90 ,  92 ,  94 . The longitudinal axis  88  of the C-ring member  84  (and the longitudinal axis  44  of the assembly  18 ) is perpendicular to each of the planes in which the circumferential ridges  90 ,  92 ,  94  lie. In the assembled swivel joint assembly  18 , the C-ring member  84  locates about the mandrel  34  and the ridges  90 ,  92 ,  94  co-operate with corresponding ridges  96 ,  98 ,  100  on the exterior surface of the mandrel  34 . The mandrel ridges  96 ,  98 ,  100  are similar in shape to those provided on the C-ring member  84  (although oriented up-side-down relative to the C-ring ridges) and are arranged circumferentially on the exterior surface of the mandrel  34 . An enlarged cross-sectional view of the mandrel ridges  96 ,  98 ,  100  is provided in  FIG. 3  of the accompanying drawings. The specific geometry of the ridges provided on the C-ring member  84  and the mandrel  34  is explained in more detail hereinafter. However, it should be understood that the engagement of the C-ring ridges with the mandrel ridges is such that axial movement of the mandrel  34  relative to the latch sub  80  is resisted (but not prevented), with an axial telescoping of the mandrel  34  into the lower component  18   b  requires greater axial force than a subsequent axial telescoping of the mandrel  34  out of the lower component  18   b.    
     The C-ring member  84  is retained freely floating about the mandrel  34  and adjacent the annular shoulder  82  by means of a split journal bushing  102  which is located uphole of the C-ring member  84 . The bushing  102  is itself retained in position by means of a plurality of pins  103  extending radially inwardly from latch sub housing into apertures/recesses in the bushing  102  and furthermore by means of a retainer nut  104  engaging an internal screwthread provided in the bore of the latch sub  80  at the upper end thereof. The retainer nut  104  is prevented from becoming unscrewed from the latch sub bore by means of a circlip  106  located uphole of the retainer nut  104 . The bushing  102  may be retained with a shoulder located in the bore of the latch sub housing downhole of the bushing  102  rather than (or as well as) with the plurality of pins  103 . Thus, it will be understood that the arrangement is such that the C-ring member  84  is retained axially fixed relative to the bore of the latch sub  80 . It should however also be understood that the external diameter of the C-ring member  84  is less than the diameter of the latch sub bore so that, as the ridges  90 ,  92 ,  94  of the C-ring member  84  move over the ridges  96 ,  98 ,  100  of the mandrel  34  during activation and deactivation of the swivel joint assembly  18 , the C-ring member is permitted to resiliently expand in a radial direction. It will be appreciated that this radial expansion is facilitated by means of the slot  86  provided in the C-ring member  84  and by its floating mount arrangement within the latch sub housing. 
     The specific geometry of the ridges provided on the C-ring member  84  and the mandrel  34  will now be described. With reference to the mandrel  34 , each of the mandrel ridges  96 ,  98 ,  100  have flat surfaces  110 ,  112  sloping (ie angled to, rather than parallel with, the longitudinal axis  44  of the assembly  18 ) and extending radially outwardly so as to intersect with a flat cylindrical plateau surface  114 . The enlarged view of the mandrel  34  shown in  FIG. 3  clearly illustrates the configuration of the mandrel ridges  96 ,  98 ,  100  and it will be seen that the flat plateau surface  114  is parallel with the longitudinal axis  44  of the assembly  18  (rather than being angled thereto). The downhole facing sloping surface  110  is arranged so as to slope more steeply relative to the longitudinal axis  44  than the uphole facing sloping surface  112 . In the embodiment of  FIG. 3 , the downhole facing flat surface  110  forms an acute angle with the longitudinal axis  44  of 70° whereas the uphole facing sloping surface  112  forms an acute angle with the longitudinal axis  44  of 10°. However, in alternative embodiments, it will be understood that these angles for the downhole and uphole facing sloping surfaces can be different (for example, 80° and 15° respectively). 
     The ridges  90 ,  92 ,  94  provided on the C-ring member  84  each have an uphole facing sloping surface  116  forming the same acute angle with the longitudinal axis  44  as the downhole facing surfaces  110  of the mandrel  34 . Similarly, the ridges  90 ,  92 ,  94  of the C-ring member  84  each comprise a downhole facing sloping surface  118  formed at the same acute angle to the longitudinal axis  44  as the uphole facing surfaces  112  of the mandrel  34 . Thus, the uphole sloping surfaces  116  of the C-ring ridges slope more steeply relative to the longitudinal axis  88  than the downhole facing surfaces  118 . The ridges  90 ,  92 ,  94  of the C-ring member  84  further comprise a cylindrical flat plateau surface  120  intersected by the uphole and downhole sloping surfaces  116 ,  118 . However, in the case of both the mandrel and the C-ring ridges, the provision of a flat plateau surface  114 ,  120  is optional. When the flat plateau surfaces  114 ,  120  are not provided, the uphole and downhole sloping surfaces intersect directly with one another. In this arrangement, said sloping surfaces are axially arranged so as to be closer to one another than when a flat plateau surface is present. The sloping surfaces do not then radially project any further than those ridges provided with flat plateau surfaces. 
     It will also be understood that the spacing between the ridges of either one of the mandrel and the C-ring provides valleys large enough for the ridges on the other of the mandrel and C-ring to locate therein. 
     With the swivel joint assembly  18  arranged in the un-activated configuration of  FIG. 2 , each mandrel ridge  96 ,  98 ,  100  is located uphole of a ridge  90 ,  92 ,  94  of the C-ring member  84 . When the arm members  38  of the landing sub  36  engage a TBR  28 , the swivel joint assembly  18  may be weight activated by allowing weight of the assembly to press down on the TBR  28 . In so doing, the downhole facing sloping surfaces  110  of the mandrel ridges  96 ,  98 ,  100  abut the uphole facing sloping surfaces  116  of the C-ring ridges  90 ,  92 ,  94 . Due to the relatively steep sloping angle of the abutting surfaces  110 ,  116  it will be understood that the mandrel  34  must be pressed downhole with a relatively large force before the C-ring will be resiliently expanded in a radial direction by virtue of said sloping surfaces  110 ,  116  sliding over one another. However, provided sufficient force is applied, each mandrel ridge may be moved downhole passed the ridge of the C-ring member  84  with which it was previously engaged. If the downhole force on the mandrel  34  is maintained, then all three of the mandrel ridges  96 ,  98 ,  100  may be moved downhole of the C-ring ridges  90 ,  92 ,  94  as shown in  FIG. 3 . In so doing, the castellations  46 ,  48  engage with one another and the swivel joint assembly  18  is placed in the activated configuration. 
     It will be appreciated that the castellations  46 ,  48  will engage one another with considerable axial force due to the high forces required to press the mandrel ridges passed the C-ring ridges. The ball bearing pack  42  is therefore provided to withstand this high dynamic shock load. 
     In order to deactivate the swivel joint assembly  18 , the mandrel  34  is pulled uphole with the result that the less steep sloping surfaces  112 ,  118  of the mandrel  34  and C-ring  84  engage and move passed each other. Again, the movement of the ridges passed one another is facilitated by a resilient radial expansion of the C-ring member  84 . Furthermore, due to the small acute angle made by said sloping surfaces  112 ,  118  with the longitudinal axis  44 , the force required to move the mandrel  34  in an uphole direction passed the C-ring member  84  is significantly less than that required to move the mandrel  34  downhole passed the C-ring member  84 . Accordingly, the swivel joint assembly  18  may be readily de-activated, but is unlikely to be activated inadvertently. 
     It will be understood that the activation characteristics of the swivel joint assembly  18  may be modified by varying the number and/or geometry of the mandrel and/or C-ring ridges. For example, the force required for activation may be increased by increasing the steepness of the relatively steep sloping surfaces  110 ,  116  of either of the mandrel and C-ring ridges. 
     The latching characteristics of the latch sub  80  may be altered through use of a modified latch sub  80 ′ in which an adjustable latch mechanism is provided (see  FIGS. 9 and 10  of the accompanying drawings). This type of latch mechanism is known in the prior art and is used in BOWEN surface jars. However, such a mechanism has not previously been used as described hereinafter. In the modified latch sub  80 ′, the C-ring latch member  84  is replaced by a latch member  84 ′ having a cylindrical wall which tapers to a reduced thickness in a downhole direction. The latch member  84 ′ is machined as a double-ended collett with each successive cut extending from a different end of the cylindrical wall. Each cut extends along the length of the cylindrical wall from one end of the wall to just short of the opposite end of the wall. Also, in the region of the latch sub  80 ′ where the latch member  84 ′ is located, the wall of the latch sub housing increases in thickness in a downhole direction. The arrangement is such that the annular space between the mandrel  34  and the latch sub housing tapers to a reduced radial dimension in the axial downhole direction. This tapering corresponds to the tapering of the latch member  84 ′ such that the latch member  84 ′ may be located in a downhole position in which most of the length of the internal surface thereof is substantially in contact with the mandrel  34  and substantially the entire length of the exterior surface thereof is in contact with the latch sub housing. In this position of the latch member  84 ′, it will be understood that there is limited room for radial expansion of the latch member  84 ′ and, accordingly, a greater axial force must be applied to the mandrel  34  in order to press the ridges  96 ,  98 ,  100  provided thereon past the ridges  90 ,  92 ,  94  provided on the latch member  84 ′. 
     The aforementioned ridges of the modified latch sub  80 ′ are of the similar size, shape and spacing as those of the latch sub  80  shown in  FIGS. 2 and 3 . However, the axial force required to pass the mandrel  34  downhole (and thereby activate the swivel joint assembly) may be reduced by retaining the latch member  84 ′ in a more uphole position within the latch sub housing. In this way, the latch member  84 ′ is located in a region where the radial dimension of the annulus between the latch sub housing and the mandrel  34  is increased. The latch member  84 ′ is therefore provided with increased room for radial expansion and, accordingly, may be radially expanded more readily upon the application of downhole axial force to the mandrel  34 . The axial position of the latch member  84 ′ may be altered through use of a control ring  130  located downhole of the latch member  84 ′. The axial position of the control ring  130  is maintained by means of a pin  132  radially extending from the housing of the latch sub  80 ′ into a control groove provided in the ring  130 . The axial position of the latch member  84 ′ may be adjusted by selecting an appropriately sized ring  130  on assembly of the latch sub  80 ′ or by rotating the ring  130  so as to locate the pin  132  in a different part of the ring control groove and thereby displacing the ring  130  uphole or downhole. 
     The present invention is not limited to the specific embodiments described above. Alternative arrangements will be apparent to a reader skilled in the art. For example, the invention is not limited to the two sizes of wellbore casing referred to above. The embodiments described above can be readily modified for use with casing diameters different to those specifically mentioned herein.