Abstract:
A wellbore cleaning system provides a relockable shearing swivel tool that can be used in tandem with a lockable weight set circulation tool. Suspended from an upper drill string is an assembly consisting of a landing sub, the lockable weight set circulation tool and relockable shearing swivel tool are located immediately above a liner top and from which is suspended a lower drills string. The lower drill string and production liner are both significantly smaller in diameter than the upper drill string and production casing such than when fluid is pumped at high rates through the entire drill string and reduced cross sectional area of the lower drills string and production liner causes a large pressure drop characterized at surface by a high pump pressure. As part of the method, an operator makes up a drill string assembly that includes an upper drill string, a lower drill string, a landing sub or device, the lockable weight set circulation tool, and the relockable shearing swivel tool. This drill string assembly is lowered into a wellbore until the landing sub is close to a liner top or other shoulder in the wellbore. The drill string is rotated and reciprocated, pumping cleaning chemicals through the entire drill string and through the production liner. The liner top is engaged with the landing sub to open a circulation path from the upper drill string to an upper annulus. The drill string is rotated and reciprocated while pumping cleaning chemicals through the upper annulus to clean the production casing.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application claims benefit of U.S. Provisional Application Ser. No. 62/221,788, filed on 22 Sep. 2015, which is incorporated herein by reference and priority of/to which is hereby claimed. 
     
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
       [0002]    Not applicable 
       REFERENCE TO A “MICROFICHE APPENDIX” 
       [0003]    Not applicable 
       BACKGROUND OF THE INVENTION 
       [0004]    1. Field of the Invention 
         [0005]    The present invention relates to an oil well down hole tool that provides a fail-safe device and method, the device operable to improve the effectiveness of cleaning a wellbore which includes at least one surface casing and at least one liner through a combination of improved rotation and reciprocation of the drill string while allowing the casing and liners to be circulated independently. 
         [0006]    2. General Background of the Invention 
         [0007]    It is typical to drill an oil well and run a series of casing which are cemented in place. In most cases, the casing will extend to a surface area and is called a surface casing. The innermost casing string is called the production casing. In some cases for reasons of economy there will be installed a liner. A liner is identical to casing except that it does not return all the way to the surface, but is instead suspended from the casing using a device known as a liner hanger. The final liner hanger which isolates the hydrocarbon bearing formation will typically be known as a production liner. 
         [0008]    It is understood that where a production liner is hung from a production casing to form a wellbore, the production liner will be of substantially smaller diameter than the production casing. It is common practice to clean a wellbore before using it to produce hydrocarbons. Those familiar with the art of wellbore cleaning will understand that there are three important elements to consider when performing a wellbore cleanup. These are rotation of the drill pipe, reciprocation of the drill pipe and circulation of the cleaning fluid in the wellbore, and as a rule of thumb, the faster the better. Suffice it to say that excluding or restricting any one of these three actions, the speed and efficiency of the cleaning operation will be compromised. 
         [0009]    Circulation is the primary method of removing unwanted debris from the wellbore. Good wellbore cleaning is a function of density, viscosity and annular velocity Annular velocity and viscosity conspire to determine the flow regime of the fluid, commonly referred to as laminar or turbulent. Chemicals such as solvents, surfactants and detergents used to clean the well work better in turbulent flow, and since it is easier to induce turbulent flow in low viscosity fluids, the preference is to prepare chemical washes with low viscosity. It is easier to carry debris from the wellbore with high viscosity fluids. A comprehensive wellbore cleanup will include pumping both high viscosity sweeping fluids and low viscosity chemical washes. These fluids are pumped as fast as possible to maximize the turbulence of the chemicals and the carrying capacity of the viscous sweeps. The fluid can be assisted further by using mechanical agitation by rotating and reciprocating the drill pipe. 
         [0010]    Drill pipe consists of a tube connected by tool joints which include threaded couplings. The tool joints are typically larger diameter than the pipe body and when screwed together form a drill string. The outer surface consists of long slender pipe bodies with multiple large diameter protrusions or tool joints. As the drill pipe is suspended in the wellbore, it rarely sits concentric in the center of the wellbore. Due to gravity and well geometry, it will usually favour one side resulting in an eccentric shaped annulus. Cleaning fluids which are being pumped will favour the larger area of the annulus which is more open. This results in a dead volume being created under the drill pipe and between the tool joints where there is little or no flow. 
         [0011]    The mechanical action of rotating the drill pipe serves to act as an impeller, drawing fluid from the main flow path under the drill pipe and consequently pushing debris out into the main flow path to be removed from the wellbore. The mechanical action of reciprocating the drill pipe uses the tool joints to drag debris upwards and when combined with the rotation causes an oscillating movement to assist in mechanical agitation of the fluid and to increase the turbulence of the fluid. 
         [0012]    If during a wellbore clean-up there is no rotation or reciprocation, there maybe significant areas of the wellbore which were not exposed to turbulent flow and will not have been properly cleaned by the chemicals and there may be debris trapped under the drill pipe. Further to this, when cleaning a wellbore with a production liner suspended from a production casing an operator will typically use what is called a tapered drill string, such that there is a larger diameter drill pipe in the production casing and small diameter drill pipe in the production liner. One reason this benefits wellbore cleaning is to maximize the annular flow rate and also to use the largest inner diameter pipe possible to reduce the pressure losses within the drill pipe while pumping. 
         [0013]    Every drilling rig will have a practical limitation on the power of their pumps, where power is a function of pressure and flow rate. Therefore, drill pipe is typically selected to provide a balance between pressure loss while pumping down the pipe and flow rate when the returning fluid passes up the annulus. The following scenario is typical, where a 9⅝″ casing is set with a 5½″ production liner. Inside the wellbore is a tapered drill string consisting of 5″ drill pipe inside the 9⅝″ casing and 2⅞″ drill pipe inside the 5½″ casing. 
         [0014]    The optimum flow rate for cleaning the 9⅝″ casing may be 13-18 barrels per minute (BPM), whereas the optimum flow rate for cleaning the 5½″ liner may be 3-5 BPM. If the operator pumps through the 5″ drill pipe and 2⅞″ drill pipe, he will most likely only be able to achieve a maximum of 5 BPM at the maximum pressure or power output of the pump. This is sufficient to clean the 5½″ liner but not the 9⅝″ casing. Therefore, it is now common practice to install a circulation device in the drill string immediately above the liner hanger. By opening this device, the operator no longer needs to pump through the 2⅞″ drill pipe and can now achieve the optimum flow rates to clean the 9⅝″ casing. 
         [0015]    There is a drawback to using a tapered string, that the strength of the Upper Drill String is much higher than the strength of the Lower Drill String. For example, a 5″ drill pipe string may be rated to 50,000 ft. lbs. while the 2⅞″ drill pipe may be rated to 13,000 ft. lbs. When rotating the drill string to clean the well, if the drill string becomes stuck, it may result in over-torquing the 2⅞″ drill pipe resulting in a ‘twist off’ or failure due to torsion. This can happen quickly before the rig safety systems detect it. This will result in a costly fishing operation. Operators are so fearful of this that they limit or prohibit the rotation of 2⅞″ drill pipe when used with a tapered string for wellbore cleaning. Patents have been issued that relate to circulation of well fluid. Examples are listed in the following table, each listed patent of the table hereby incorporated herein by reference. 
         [0000]    
       
         
               
               
               
             
           
               
                   
               
               
                 Patent No. 
                 Title 
                 Issue Date 
               
               
                   
               
             
             
               
                 6,152,228 
                 Apparatus and Method for  
                 Nov. 28, 2000 
               
               
                   
                 Circulating Fluid in a Borehole 
                   
               
               
                 6,279,657 
                 Apparatus and Method for  
                 Aug. 28, 2001 
               
               
                   
                 Circulating Fluid in a Well 
                   
               
               
                   
                 Bore 
                   
               
               
                 7,703,533 
                 Shear Type Circulating Valve and  
                 Apr. 27, 2010 
               
               
                   
                 Swivel with Open Port  
                   
               
               
                   
                 Reciprocating Feature 
                   
               
               
                 8,403,067 
                 Repeatable, Compression  
                 Mar. 26, 2013 
               
               
                   
                 Set Downhole Bypass Valve 
                   
               
               
                 6,497,295 
                 Torque Limiting Tool 
                 Dec. 24, 2002 
               
               
                 7,011,162 
                 Hydraulically Activated Swivel for  
                 Mar. 14, 2006 
               
               
                   
                 Running Expandable  
                   
               
               
                   
                 Components with Tailpipe 
                   
               
               
                 7,798,230 
                 Downhole Tool 
                 Sep. 21, 2010 
               
               
                 2014/0299379 
                 Down-Hole Swivel Sub 
                 Oct. 9, 2014 
               
               
                 GB2272923 
                 Apparatus for Circulating Fluid 
                 Jun. 1, 1994 
               
               
                   
               
             
          
         
       
     
         [0016]    U.S. Pat. No. 6,279,657 discloses a circulating tool for circulating fluid in a borehole which features an obturating member to selectively open and close a circulation device, while simultaneously disengaging and engaging a splined drive mechanism. The tool is run immediately above a liner top and typically run with a tapered string for cleaning wellbores with a production casing and production liner as described previously. It works by allowing fluid to be pumped down through the string to clean the production liner, then can be opened by setting the tool on the liner top, opening the circulation ports and simultaneously disengaging a spline which allows the production casing to be cleaning at a high flow rate, and also while rotating the 5″ drill pipe. The 2⅞″ drill pipe does not rotate as the spline has disengaged. The limitation of this method is that it is not possible to reciprocate the drill pipe while cleaning the production casing since weight must be maintained to keep the circulation ports opened. Although the design of the tool does not prevent either reciprocation or rotation when cleaning the production liner, as disclosed previously, the operator may either limit or prohibit rotation for fear of a ‘twist off’. 
         [0017]    GB2272923 discloses and apparatus for circulating fluid. The device is used in the same types of wellbores including a production liner and production casing, whereby the device is engaged with a liner top and by applying weight a circulation port is opened to allow displacement of the production casing. There are two types of tools disclosed which perform the same function. The limitation of these tools are that there is no way to rotate or reciprocate the string when the circulation ports are opened. Furthermore there is also the risk of ‘twist-off’ of the 2⅞″ drill pipe as disclosed previously. 
         [0018]    U.S. Pat. No. 6,497,295 discloses a torque limiting tool which features a shear-able member which when an excess torque is detected it prevents a ‘twist-off’ by shearing the same member and sending a pressure signal to surface. This device can be used with U.S. Pat. No. 6,279,657 to overcome the issue of ‘twist-off’ except that the tool is not readily resettable. After removing a drill string from the production liner and due to the narrow clearance between the drill string and the liner, it is possible for debris or junk to become wedged between the two and the string becomes stuck. If this occurs it is highly desirable to be able to rotate the pipe to attempt to dislodge it. In this case if &#39;295 shear-able member has been sheared, it will not be possible to rotate the string free resulting in an expensive fishing operation. 
         [0019]    It is therefore desirable to use a device or system which allows unrestricted rotation and reciprocation while selectively opening and closing a circulation device to allow the production liner and production casing to the cleaned without compromising either three of these actions. 
       BRIEF SUMMARY 
       [0020]    The apparatus of the present invention solves the problems confronted in the art in a simple and straightforward manner. The present invention provides a relockable shearing swivel tool which prevents accidental twist-off of a drill string, and which can be relocked by dropping an activation ball. 
         [0021]    The present invention provides an oil well relockable shearing swivel downhole tool apparatus that includes an elongated tool body having upper and lower end portions, an upper section and a lower section. 
         [0022]    An upper connection enables connection to an upper drill string section. 
         [0023]    A lower connection enables connection to a lower drill string section. 
         [0024]    An axial bore enables fluid communication between the upper and lower end portions. 
         [0025]    The lower end portion of the tool body provides a ball seat and a ball retainer below the ball seat, inside the lower sub. 
         [0026]    A first member is placed below the upper connection, with first interlocking portions on the first member. 
         [0027]    A second member is placed in between the first member and the lower connection, and second interlocking portions on a second member. 
         [0028]    A plurality of shear pins are placed on the tool body, the fist and second interlocking portions being spaced apart a first distance in an initial position wherein relative rotation of the upper section relative to the lower section is prevented by the said shear pins. 
         [0029]    A ball is sized and shaped to flow from the upper connection to the ball seat. 
         [0030]    A drive nut is located above the ball seat. 
         [0031]    A spring is placed in the tool body below the drive nut. 
         [0032]    Wherein the ball is movable with the ball seat and the drive nut responsive to increased pressure in the bore above the ball to define a spring compressed position wherein the spring is compressed. 
         [0033]    Wherein the ball is movable from the ball seat downwardly into the ball retainer responsive to increased pressure in the bore above the ball wherein the spring is released to lift the drive nut and the second member and wherein the first and second interlocking portions engage and interlock. 
         [0034]    In one embodiment, the ball retainer has one or more bypass ports. 
         [0035]    In one embodiment, the tool body includes a knocker sub below the upper connection. 
         [0036]    In one embodiment, the shear pins form a connection between the knocker sub and the upper end portion of the tool body. 
         [0037]    In one embodiment, the tool body carries a pump. 
         [0038]    In one embodiment, the tool body includes an upper sub, a knocker sub and a lower sub. 
         [0039]    In one embodiment, a threaded connection joins the upper sub to the knocker sub. 
         [0040]    In one embodiment, a connection joins the knocker sub to the lower sub. 
         [0041]    In one embodiment, the balls seat is in the lower sub. 
         [0042]    In one embodiment, the drive nut is in the lower sub. 
         [0043]    In one embodiment, the upper sub has a lower end and the lower sub extends upwardly above the lower end of the upper sub. 
         [0044]    In one embodiment, the knocker sub has a lower end and the lower sub extends upwardly above the lower end of the knocker sub. 
         [0045]    In one embodiment, the lower sub has intake ports that enable fluid intake to the pump at a position that is above the lower end of the upper sub. 
         [0046]    In one embodiment, the spring is in the lower sub. 
         [0047]    In one embodiment, the shear pins connect the upper sub to the knocker sub at a position above the lower sub. 
         [0048]    The present invention can include a lockable weight set circulation tool that can be run in tandem with the relockable shearing swivel tool (see  FIG. 5 ). 
     
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
         [0049]    For a further understanding of the nature, objects, and advantages of the present invention, reference should be had to the following detailed description, read in conjunction with the following drawings, wherein like reference numerals denote like elements and wherein: 
           [0050]      FIG. 1  shows the tool in an initial position where the upper drill string and the lower drill string are locked rotationally by torque shear pins; 
           [0051]      FIG. 2  shows the tool in a second sequential “cocked” position where the torque shear pins have been ruptured resulting in the upper drill string and lower drill string being able to rotate independently, and where a ball has been pumped down and has landed on a ball seat which has moved the spring housing and associated components downwards compressing the spring; 
           [0052]      FIG. 3  shows the tool in a third sequential and relocked position where the ball retainer has traveled to a downwards position, and the spring housing and associated components have been moved in an upwards position by the spring which results in the interlocking portions or castellations of the upper drive nut and lower drive nut engaging the conspiring to lock the upper drill string and the lower drill string rotationally; 
           [0053]      FIG. 4  shows the tool as illustrated in  FIG. 1  in a perspective or isometric cutaway view to illustrate the components of the screw pumping mechanism; 
           [0054]      FIG. 5  shows an exemplary application of the tool in an oil well and connected between an upper drill string and lower drill string and connected to a circulation tool and a landing sub where the tool is located above a liner hanger; 
           [0055]      FIG. 6  is a sectional elevation view showing the lockable weight set circulation tool that can be used in tandem with the swivel tool of  FIGS. 1-4 ; 
           [0056]      FIG. 7  is a sectional view taken along lines A-A of  FIG. 6 . 
           [0057]      FIG. 8  is a sectional elevation view showing the lockable weight set circulation tool that can be used in tandem with the swivel tool of  FIGS. 1-4 ; 
           [0058]      FIG. 9  is a sectional elevation view showing the lockable weight set circulation tool that can be used in tandem with the swivel tool of  FIGS. 1-4 ; 
           [0059]      FIG. 10  is a sectional elevation view showing the lockable weight set circulation tool that can be used in tandem with the swivel tool of  FIGS. 1-4 ; 
           [0060]      FIG. 11  is a fragmentary perspective view of the preferred embodiment of the apparatus of the present invention; and 
           [0061]      FIG. 12  is a schematic diagram showing an expanded view of the index slot. 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0062]      FIGS. 1-5  show the preferred embodiment of the apparatus of the present invention designated generally by the numeral  56 . Relockable shearing swivel tool apparatus  56  provides an elongated tool body  62  that includes connectable sections, namely top sub  1 , knocker sub  19 , and bottom sub  29 . The tool body  62  has upper connection  2  enabling connection to upper drill string  3  (see  FIG. 5 ). In the exemplary installation  65  of  FIG. 5  can be seen placement of production casing  54 , upper annulus  60 , lower annulus  61 , lower drill string  31 , production liner  55  and liner hanger  59 . Above liner hanger  59  is landing sub  58 . Above landing sub  58  is lockable weight set circulation tool  100 . Above lockable weight set circulation tool  100  is relockable shearing swivel tool  56 . Axial bore  4  enables fluid flow through upper drilling string  3 , tool  56 , tool  100 , landing sub  58 , and lower drill string  31 . 
         [0063]      FIGS. 1-4  show relockable shearing swivel tool  56  in more detail. The tool  56  has axial bore  4  that is open ended, extending from upper connection  2  to lower connection  30 .  FIG. 1  shows the tool  56  in an initial position where upper drill string  3  and lower drill string  31  are locked rotationally by torque shear pins  16 . By creating differential torque in upper and lower drill strings  3 ,  31  the torque shear pins  16  are sheared so that the upper and lower drill strings  3 ,  31  are able to rotate independently (see  FIG. 2 ). In  FIG. 2 , ball  53  has been pumped downwardly via axial bore  4  and landed upon ball seat  46 . Increasing pump pressure forces ball  53  and spring housing  39  downwardly compressing spring  42  (see  FIG. 2 ). In this position, ball  53  rests upon seat  46 . Ball retainer  44  is held by a series of shear screws  47 . 
         [0064]    Additional pump pressure is applied to force ball  53  down, past ball seat  53  and into ball retainer  44 . Ball retainer  44  is located in bottom sub  29 . Ball retainer  44  has lower face  50 , O-rings  45  and internal abutment  48 . When ball retainer  44  travels down responsive to pump pressure, it has face  50  that rests upon internal abutment  51  of bottom sub  29 . Ball retainer  44  has bypass ports  49 . 
         [0065]    Once ball  53  is pumped below seat  46  and into ball retainer  44 , spring  42  forces spring housing up to the position seen in  FIG. 3 . Spring housing  39  and associated components are moved up by spring  42  which results in the interlocking portion or castellations  52  of upper drive nut  6  engaging the interlocking portion or castellations  63  of lower drive nut  33  (see  FIG. 3 ). The castellations  52 ,  63  are locked together in  FIG. 3 . Once so locked together, the upper drill string  3  can be rotated or reciprocated with lower drill string  31  as necessarily occurs during well cleaning. 
         [0066]      FIG. 4  shows in perspective view the components of the screw pumping mechanism  65 . Pumping mechanism  65  is used to remove heat from the tool body  62 . Water courses  20  are placed in between torque shear pins  16 . Holes  15  are provided to hold the pins  16 . Water courses  20  communicate with bypass channels  13 . Internal cylindrical portion  23  has helical grooves  12 , castellations  22 , and lower stator bearing  11 . 
         [0067]    The relockable shearing swivel tool  56  and its components will now be discussed in more detail. The top sub  1  is an elongated member with an upper connection  2  to allow it to be connected to upper drill string  3 . Axial bore  4  allows pumping of cleaning fluids. Spline  5  is provided to rotationally lock it to an upper drill nut  6 . Male thread  7  allows connection to impeller nut  8 . A series of castellations  9  rotationally lock to a lower rotator bearing  10 . A series of helical grooves  12  which when the top sub  1  rotates acts as a screw pump. A series of bypass channels  13  pump the fluid through an upper thrust bearing  14 . A series of holes  15  house torque shear pins  16  where the bypass channels  13  run between the holes  15 . A shoulder area  17  accommodates upper thrust bearing  14 . 
         [0068]    The upper trust bearing  14  is locked to top sub  1  by a series of bolts  18  and is placed between the top sub  1  and a knocker sub  19  so that when the top sub  1  and knocker sub  19  rotate relative to each other, the upper thrust bearing  14  wears sacrificially. There are water courses  20  cut in the load bearing face of upper thrust bearing  14  which allows a pumped fluid to pass which act to cool and lubricate the upper thrust bearing  14 . The upper thrust bearing  14  can be made of a bronze alloy but could be of other construction such as ceramics, polycrystalline diamond, ball bearing or other. 
         [0069]    The knocker sub  19  has a face at an upper end which contacts the upper thrust bearing  14 . A male thread  21  at the opposite which engages to and rotationally locks with the bottom sub  29 . A series of castellations  22  rotationally lock to lower stator bearing  11 . Internal cylindrical portion  23  houses the aforementioned top sub  1  where the internal cylindrical portion  23  and helical grooves  24  form the housing and rotor of the screw pump. The series of torque shear pins  16  rotationally lock the knocker sub  19  and top sub  1  such that when the top sub  1  is rotated by the upper drill string  3 , torque is transmitted through it through the torque shear pins  16 , through the knocker sub  19 , through the bottom sub  29  and the lower drill string  31 . The lower stator bearing  11  and lower rotor bearing  10  can be made of PCD polycrystalline diamond, but could be of other construction such as bronze alloy, ceramics, polycrystalline diamond, ball bearings or other. 
         [0070]    Impeller nut  8  features an internal thread which locks it rotationally to the top sub  1  as well as carrying the tensile load of the tool body. Impeller nut  8  features a series of helical grooves  24  cut on the external surface which when placed inside an internal bore  25  of the bottom sub  29  forms rotor and housing of a screw pump. Rotary seals  26  form a hydraulic seal with the aforementioned internal bore  25 . Two internal O-rings  27  form a hydraulic seal with the top sub  1 . The two seals  26  combine to form an hydrostatic barrier between the axial bore  4  and annulus  28 , thus ensuring cleaning chemicals and fluids can be pumped through the tool  56 . Bottom sub  29  is an elongated member with lower connection  30  to allow it to be connected to lower drill string  31 . Axial bore  4  allows pumping of cleaning fluids. Internal spline  32  engages lower drive nut  33 . A series of intake ports  34  (e.g., formed by drilling a series of radial holes) immediately adjacent to the impeller nut  8 , helical grooves  24  such that they allow annular fluid to enter the aforementioned screw pump mechanism. Radial threaded holes accommodate locking pins  35 , an internal abutment  36  to locate stop ring  37 ; an internal abutment  38  to engage with spring housing  39 . 
         [0071]    Spring housing  39  is an elongated member which resides in the bottom sub  29  and forms the main structure in a sub-assembly which acts as the relocking element of the invention. Spring housing  39  features a threaded portion  40  at an upper end which engages with the lower drive nut  33 . Holes which accommodate shear screws  41  temporarily lock to the aforementioned stop ring  37 . A shaft accommodates spring  42  which is mounted about the shaft and compressed between the lower drive nut  33  and the stop ring  37 . 
         [0072]    During use, the tool body  62  is connected in the drill string between the upper drill string  3  and lower drill string  31 . The upper drill string  3  is rotated which transmits torque and rotation through the tool body  62  to the lower drill string  31 . The drill string can be rotated and reciprocated, allowing the well to be cleaned. It is also possible to function circulation tools to assist in the cleaning If a predetermined torque limit is exceeded, the torque shearing pins  16  shear and the tool  56  becomes a swivel to allow the upper drill string  3  to rotate independently from the lower drill string  31 , thus preventing an accidental twist-off of the lower drill string  31 . Depending if the tool  56  is in compression or tension, the load axial load of the string will be borne by the upper thrust bearing  14  [compression] or the lower rotor/lower stator bearing  10  [tension] respectively. The rotation of the parts generates heat. The lower bearing  10  is cooled by circulating wellbore fluid through screw type fluid pump  65 . When the upper  3  and lower components  31  of the tool  56  rotate with respect to each other, fluid is drawn from the annulus  28  through the entry ports and along the helical grooves  12  in the impeller nut  8  in an upwards direction. The fluid then flows between the lower stator bearing  11  and the lower rotor bearing  10  to cool it. Fluid is then drawn by the helical grooves cut in the top sub  1  and is diverted through the bypass channels  13  and through the water courses  20  which keep up the upper bearing  14  cool and lubricated. 
         [0073]    When it is desired to relock the swivel to allow rotation to be applied between the top sub  1  and bottom sub  29 , a ball  53  (or dart or other suitable or like object) can be pumped down to land on a ball seat  46  on the ball retainer  44 . As pressure is applied, the shear screw  47  located between the spring housing  39  and stop ring  37  shear and spring housing  39  moves downwards compressing the spring  42 . The spring housing  39  will then abut against the bottom sub  29  and as pressure increases the shear screws  47  related to the ball retainer  44  will shear, which releases the downward force and causes the spring  42  to move the spring housing  39  upwards. As this happens, the catellations  52 ,  53  between the upper drive nut  6  and lower drive nut  33  engage. Torque can now be applied between the upper  3  and lower drill strings  31  by the connection of the top sub  1 , upper drive nut  6 , lower drive nut  33  and bottom sub  29 . 
         [0074]    Lockable weight set circulation tool  100  of  FIGS. 6-12  can be run in tandem with the relockable shearing swivel tool  56  (as seen in  FIG. 5 ) to allow selective opening and closing of radial circulation ports to allow circulation of the upper annulus  60  and lower annulus  61  independently. The apparatus  100  is functioned by the application of string weight, typically by using landing sub  58  which can engage liner hanger  59  (see  FIG. 5 ) and by the application of weight can cycle the tool  100  through various operating positions. Whereas there are devices which require the continued application of weight to keep the circulation ports opened, the apparatus  100  device is activated by the application of weight and can have the circulation ports locked or closed as desired by the operator and without the continued application of weight. 
         [0075]    The apparatus  100  disclosed uses a guide pin which locates in a continuous indexing slot milled onto an indexing sleeve, where each application and subsequent removal of weight to the tool shall cycle the tool the next indexing position. The device follows an infinite repeating cycle of CLOSED&gt;OPEN&gt;CLOSED&gt;CLOSED&gt;OPEN&gt;CLOSED&gt;CLOSED&gt;OPEN, but can be reconfigured to follow other combinations such as CLOSED&gt;OPEN&gt;CLOSED&gt;OPEN. 
         [0076]    In  FIGS. 6-12 , apparatus  100  has a tool body that includes top sub  101 , spline mandrel  106 , drive mandrel  108 , and knocker sub  110 . The top sub  101  is an elongated member with an upper connection  102  to allow it to be connected to an upper drill string  3 , an axial bore  104  to allow pumping of cleaning fluids and a threaded connection  105  to allow connection to spline mandrel  106 . 
         [0077]    Spline mandrel  106  is an elongated member with threaded connection  105  to connect to the top sub  101 , axial bore  104  to allow pumping of cleaning fluids, a spline  107  to rotationally lock it to drive mandrel  108  and allow the drive mandrel  108  and spline mandrel  106  to slide telescopically. 
         [0078]    Shoulder  109  abuts against shoulder  145  of spline mandrel  106  which can hold the full weight of the drill string  3 ,  31  when required. A series of radial internal circulation ports  111  allow a flow path between the axial bore  104  and the annulus  112  when desired, which is straddled by seal  113 . Index sleeve  114  is located at the lower end of male thread  115  which can accommodate a plug  116 . 
         [0079]    Drive mandrel  108  is an elongated member with a lower connection  117  to allow it to be connected lower drill string  31 , axial bore  104  allows pumping of cleaning fluids. Threaded connection  119  at the upper end of drive mandrel  108  connects to the knocker sub  110 . Internal spline portion of drive mandrel  108  engages with the spline  107  of spline mandrel  106 . A series of holes accommodate shear pins  120  which mate with the drive mandrel  108 . A series of radial external circulation ports  121  are provided to selectively circulate fluid from the axial bore  104  to the annulus  112 . A hole is in drive mandrel  108  is provided to accommodate a guide pin  122 . An internal seal bore  123  accommodates seals. A separate seal bore  124  accommodates plug  140 . 
         [0080]    Knocker sub  110  is fixed to the drive mandrel  108  by way of threaded connection. Knocker sub  110  is mounted onto the drive mandrel  108  and is used to restrict the slide-able movement of the spline mandrel  106  by shoulder  125  of top sub abutting against a shoulder of knocker sub  110 .  FIG. 6  shows a non-abutting condition, and  FIG. 8  shows an abutting condition. 
         [0081]    Index sleeve  114  ( FIG. 11 ) is mounted on the drive sleeve/spline mandrel  106  at the lower end of spline mandrel  106 , and located between a shoulder and the plug  116 , such that index sleeve  114  cannot slide relative to the drive sleeve/spline mandrel  106 , but also features two bearings  127  which allow index sleeve  114  to rotate. The index sleeve  114  also features a continuous indexing slot  128  which accommodates guide pin  122  such that indexing slot  128  follows a cyclical pattern through a series of functional positions. Indexing slot  128  dictates the axial position of the drive mandrel  108  and spline mandrel  106  in relation to each other, and hence the alignment of the external circulation ports  121  and internal circulation ports  111  in relation to each other. These positions are defined (see  FIG. 12 ) as the “open”  129 , “closed”  130 , “cocked long”  131  and “cocked short”  132 . A set of seals  135  are mounted either side of the internal circulation ports  111  on the drive sleeve and seal on the internal bore  123 . A further seal can be located on the plug  116  which forms an hydraulic seal around the guide pin  122  preventing leakage past it. Each seal  135  is restrained by a lock ring  136  and screws  137 . When in the open position, the external  121  and internal  111  circulation ports align to allow a flow path from the axial bore  104  to the annulus  112 . In the “closed”  130 , “cocked long”  131  and “cocked short”  132  positions, the internal seal bore  123  seals against the seals  113  and closes the flow path. 
         [0082]    The plug  116 , 140  is connected to the lower end of the spline mandrel  106 . It houses one of the aforementioned seals  135  which conspire with an O-ring  138  to form an hydraulic barrier. The plug  116  has an elongated end  139  with a bulbous feature  140  housing further O-rings  141  as well as a series of bypass ports  142 , such that when the apparatus  100  is in the open  129  position, the O-rings  141  are stung into a seal bore on the drive mandrel  108  which seals the axial bore  104  preventing fluid from passing in either direction, and because the circulation ports are also in the open position, fluid pumped from the surface will exit the circulation ports and none can pass to the lower drill string  31 . Furthermore, when the apparatus  100  is in any of the other positions, the bulbous feature  140  will not engage the seal bore  124  and fluid can be pumped through the axial bore  104 , through the bypass ports  142 , and through an annulus  143  created between the seal bore  124  and the elongated end  139 . 
         [0083]    In the initial “closed”  130  position, the tool has shear pins  120  intact which prevents axial compressive load causing the tool  100  to stroke, provided the axial load does not exceed the maximum shear strength of the shear pins  120 . The selection of the shear pins  120  is important as this determines how the tool  100  may interact with other tools in the drill string. It also allows limited weight to be applied to the lower drill string  31  in the event it is required to drill cement or other debris in the wellbore without accidentally functioning the tool  100 . In this position it is possible to pump cleaning chemicals and fluids downwards through the upper drills string  3  and lower drill string  31  to clean the production liner  55 . 
         [0084]    When it is desired to open the circulation port, a compressive load is applied to the tool  100 . This is done by lowering the drills string  3 ,  31  until a landing sub  58  which is connected below the tool  100  lands onto a shoulder in the wellbore such as a liner top. As weight is continued to be applied, the shear pins  120  will rupture and the tool  100  will stroke moving the guide pin  122  along the indexing slot  128  until it reaches the cocked long  131  position. 
         [0085]    The operator then raises the drill string  3 ,  31  until a tensile load strokes the tool  100  open and the guide pin  122  travels to the “open”  129  position aligning the internal circulation ports  111  and external circulation ports  121 . The operator can then pump chemicals down the upper drill string  3  into the annulus  112  to clean the production casing  54 . 
         [0086]    The operator can then repeat the action of applying weight by lowering the drill string  3 ,  31  until the landing sub  58  engages the liner top to cycle the tool to the “closed”  130  position to allow further circulation of fluids through the production liner  55 . 
         [0087]    The device  100  can be cycled infinitely by the operator following repeating cycles of CLOSED&gt;OPEN&gt;CLOSED&gt;CLOSED&gt;OPEN&gt;CLOSED&gt;CLOSED&gt;OPEN. The index slot  128  could be reconfigured to follow other combinations such as CLOSED&gt;OPEN&gt;CLOSED&gt;OPEN. 
         [0088]      FIG. 6  shows the tool in an initial closed position where the shear pins  120  are intact. The guide pin  122  is located in the CLOSED position of the indexing slot  128 . The shoulder  109  of the knocker sub  110  is engaged to the shoulder  145  of the spline mandrel  106  and the internal circulation ports  111  and external circulation ports  121  are misaligned from the axial bore  104  to the annulus, and the plug  140  is not stung into the seal bore  124  allowing fluid to be pumped through the axial bore  104  without restriction.  FIG. 7  is a sectional view of the tool taken from the lines A-A in  FIG. 6 . 
         [0089]      FIG. 8  shows the tool in a cocked long position where axial force has been applied through the upper connection  102  and lower connection  117  which has sheared the shear pin  120  resulting in the tool stroking The spline  107  between the spline mandrel  106  and drive mandrel  108  guides the two components  106 , 108  as they stroke relative to each other. Simultaneously, the guide pin  122  travels through the index slot  128  in the direction illustrated by the arrow shown in  FIG. 12 , then following the index slot  128  at an angle until guide pin  122  comes to rest at the cocked long position. In this position [cocked long position] the top sub  101  and knocker sub  110  have abutted against each other restricting any further stroking of the tool. Furthermore, the internal circulation ports  111  and external circulation ports  121  are misaligned preventing any circulation from the axial bore  104  to the annulus, and the plug  140  is not stung into the seal bore  124  allowing fluid to be pumped through the axial bore  104  without restriction. 
         [0090]      FIG. 9  shows the tool in an open position where tensional force has been applied through the upper connection  102  and the lower connection  117  causing the tool to stroke apart, where the guide pin  122  moves along the index slot  128  in first a straight and then angular path until it comes to rest in the open position (see  FIG. 12 ). In this position [open] the internal circulation ports  111  and external circulation ports  121  are aligned allowing a free circulation path from the axial bore  104  to the annulus  112 , and the plug  140  is stung into the seal bore  124  preventing fluid to be pumped to the lower drill string. 
         [0091]      FIG. 10  shows the tool in the cocked short position where axial force has been applied through the tool moving the guide pin  122  in the direction illustrated by the arrow (see  FIG. 12 ), then following the index slot  128  at an angle until it comes to rest at the cocked short position; the internal circulation ports  111  and external circulation ports  121  are misaligned preventing any circulation from the axial bore  104  to the annulus  112 , and the plug  140  is not stung into the seal bore  140  allowing fluid to be pumped through the axial bore  104  without restriction. 
         [0092]      FIG. 11  shows an external view of the index sleeve  114  with the index slot  128  cut in a continuous path around the external surface.  FIG. 12  shows an expanded view of the index slot  128  as if unwrapped from the circumference of the index sleeve  114  and laid flat. It shows the guide pins  122  in the various positions OPEN ( 129 ), CLOSED ( 130 ), COCKED LONG ( 131 ) and COCKED SHORT ( 131 ). 
         [0093]    The following is a list of parts and materials suitable for use in the present invention: 
         [0000]    
       
         
               
             
               
               
               
             
               
               
               
             
           
               
                   
               
               
                 PARTS LIST: 
               
             
          
           
               
                   
                 PART NUMBER 
                 DESCRIPTION 
               
               
                   
                   
               
             
          
           
               
                   
                 1 
                 top sub 
               
               
                   
                 2 
                 upper connection 
               
               
                   
                 3 
                 upper drill string 
               
               
                   
                 4 
                 axial bore 
               
               
                   
                 5 
                 spline 
               
               
                   
                 6 
                 upper driver nut 
               
               
                   
                 7 
                 male thread 
               
               
                   
                 8 
                 impeller nut 
               
               
                   
                 9 
                 castellations 
               
               
                   
                 10 
                 lower rotor bearing 
               
               
                   
                 11 
                 lower stator bearing 
               
               
                   
                 12 
                 helical grooves 
               
               
                   
                 13 
                 bypass channels 
               
               
                   
                 14 
                 upper thrust bearing 
               
               
                   
                 15 
                 holes 
               
               
                   
                 16 
                 torque shear pins 
               
               
                   
                 17 
                 shoulder area 
               
               
                   
                 18 
                 bolts 
               
               
                   
                 19 
                 knocker sub 
               
               
                   
                 20 
                 water courses 
               
               
                   
                 21 
                 male thread 
               
               
                   
                 22 
                 castellations 
               
               
                   
                 23 
                 internal cylindrical portion 
               
               
                   
                 24 
                 helical grooves 
               
               
                   
                 25 
                 internal bore of the bottom sub 
               
               
                   
                 26 
                 rotary seals 
               
               
                   
                 27 
                 O-rings 
               
               
                   
                 28 
                 annulus 
               
               
                   
                 29 
                 bottom sub 
               
               
                   
                 30 
                 lower connection 
               
               
                   
                 31 
                 lower drilling string 
               
               
                   
                 32 
                 internal spline 
               
               
                   
                 33 
                 lower drive nut 
               
               
                   
                 34 
                 intake ports 
               
               
                   
                 35 
                 locking pins 
               
               
                   
                 36 
                 internal abutment 
               
               
                   
                 37 
                 stop ring 
               
               
                   
                 38 
                 internal abutment 
               
               
                   
                 39 
                 spring housing 
               
               
                   
                 40 
                 threaded portion 
               
               
                   
                 41 
                 shear screws 
               
               
                   
                 42 
                 spring 
               
               
                   
                 43 
                 O-ring 
               
               
                   
                 44 
                 ball retainer 
               
               
                   
                 45 
                 O-ring 
               
               
                   
                 46 
                 ball seat 
               
               
                   
                 47 
                 shear screws 
               
               
                   
                 48 
                 internal abutment 
               
               
                   
                 49 
                 bypass ports 
               
               
                   
                 50 
                 lower face 
               
               
                   
                 51 
                 internal abutment 
               
               
                   
                 52 
                 castellations 
               
               
                   
                 53 
                 ball 
               
               
                   
                 54 
                 production casing 
               
               
                   
                 55 
                 production liner 
               
               
                   
                 56 
                 relockable shearing swivel tool 
               
               
                   
                 58 
                 landing sub 
               
               
                   
                 59 
                 liner hanger 
               
               
                   
                 60 
                 upper annulus 
               
               
                   
                 61 
                 lower annulus 
               
               
                   
                 62 
                 tool body 
               
               
                   
                 63 
                 castellations 
               
               
                   
                 64 
                 installation 
               
               
                   
                 65 
                 pumping mechanism/screw type fluid 
               
               
                   
                   
                 pump 
               
               
                   
                 100 
                 tool/lockable weight set circulation 
               
               
                   
                   
                 tool/apparatus 
               
               
                   
                 101 
                 top sub 
               
               
                   
                 102 
                 upper connection 
               
               
                   
                 103 
                 tool body 
               
               
                   
                 104 
                 axial bore 
               
               
                   
                 105 
                 threaded connection 
               
               
                   
                 106 
                 spline mandrel 
               
               
                   
                 107 
                 spline 
               
               
                   
                 108 
                 drive mandrel 
               
               
                   
                 109 
                 shoulder 
               
               
                   
                 110 
                 knocker sub 
               
               
                   
                 111 
                 internal circulation ports 
               
               
                   
                 112 
                 annulus 
               
               
                   
                 113 
                 seals 
               
               
                   
                 114 
                 index sleeve 
               
               
                   
                 115 
                 male thread 
               
               
                   
                 116 
                 plug 
               
               
                   
                 117 
                 lower connection 
               
               
                   
                 118 
                 internal spline portion 
               
               
                   
                 119 
                 threaded connection 
               
               
                   
                 120 
                 shear pins 
               
               
                   
                 121 
                 external circulation ports 
               
               
                   
                 122 
                 guide pin 
               
               
                   
                 123 
                 internal seal bore 
               
               
                   
                 124 
                 seal bore 
               
               
                   
                 125 
                 shoulder 
               
               
                   
                 126 
                 shoulder 
               
               
                   
                 127 
                 bearings 
               
               
                   
                 128 
                 indexing slot 
               
               
                   
                 129 
                 open 
               
               
                   
                 130 
                 closed 
               
               
                   
                 131 
                 cocked long 
               
               
                   
                 132 
                 cocked short 
               
               
                   
                 133 
                 arrow 
               
               
                   
                 134 
                 repeated feature 
               
               
                   
                 135 
                 seal 
               
               
                   
                 136 
                 lock ring 
               
               
                   
                 137 
                 screws 
               
               
                   
                 138 
                 O-ring 
               
               
                   
                 139 
                 elongated end 
               
               
                   
                 140 
                 bulbous feature 
               
               
                   
                 141 
                 O-rings 
               
               
                   
                 142 
                 bypass ports 
               
               
                   
                 143 
                 annulus 
               
               
                   
                 145 
                 annulus 
               
               
                   
                   
               
             
          
         
       
     
         [0094]    All measurements disclosed herein are at standard temperature and pressure, at sea level on Earth, unless indicated otherwise. All materials used or intended to be used in a human being are biocompatible, unless indicated otherwise. 
         [0095]    The foregoing embodiments are presented by way of example only; the scope of the present invention is to be limited only by the following claims.