Patent Publication Number: US-11035187-B2

Title: Single ball activated hydraulic circulating tool

Description:
SUMMARY 
     The present invention is directed to a circulating sub. The sub comprises an elongate outer member having a longitudinal internal bore extending therethrough and at least one exit port, and an elongate inner member disposed within the internal bore and having an internal channel extending therethrough, in which a nozzle is formed within the channel. The sub further comprises a plurality of locking elements adapted to releasably maintain the inner and outer members in a longitudinally fixed relationship. Each locking element comprises an elongate arm having a projecting ear positionable within a groove formed within the internal bore, and a catch member attached to the arm and partially extending within the channel. 
     The inner member of the sub is configured to move relative the outer body such that the inner member is movable between: (1) a locked position, in which fluid does not pass through the exit port; and (2) an open position, in which fluid passes through the exit port. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic view of a drilling system formed from a series of interconnected rigid pipe sections. 
         FIG. 2  is a schematic view of a drilling system formed from coiled tubing. 
         FIG. 3  is cross-sectional view of a circulation sub. The cross-section is taken along the longitudinal axis of the sub. The sub is shown in the locked position. 
         FIG. 4  is the view of  FIG. 3  with the sub shown in the intermediate position. 
         FIG. 5  is the view of  FIG. 3  with the sub shown in the open position. 
     
    
    
     DETAILED DESCRIPTION 
     In oil and gas drilling operations, it is important to keep fluid circulating within the wellbore to maintain effective pressure and to keep the drill string and drill bit cooled and lubricated. In some cases, the fluid may flow into one or more geological formations surrounding the wellbore, leading to a decrease in fluid circulation. Circulation will need to be increased within the wellbore when this occurs. 
       FIG. 1  shows a schematic view of a drilling system  10  used in oil and gas drilling operations. The drilling system  10  comprises surface equipment  12 , an elongate tubular string or drill string  14 , and a drill bit  16 . The surface equipment  12  sits on a ground surface  18 . The drill string  14  and the drill bit  16  are shown underground within a wellbore  20 . The drill string  14  is made up of a plurality of rigid pipe sections  21  attached end to end. 
     The drilling system  10  works to advance the drill string  14  and the drill bit  16  down the wellbore  20  during drilling operations by rotating the drill string  14  and the drill bit  16 . A bottom hole assembly  22  is connected to a terminal end  24  of the drill string  14  prior to the drill bit  16 . The bottom hole assembly  22  may comprise one or more tools used in drilling operations, such as a circulation sub, mud motors, telemetry equipment, hammers, etc. During operation, fluid may be pumped down the drill string  14  and exit the drill bit  16  in order to flow into the wellbore  20 . 
       FIG. 2  shows a schematic view of a coiled tubing drilling system  26  used in oil and gas drilling operations. The coiled tubing system  26  comprises surface equipment positioned at the ground surface  18 . The surface equipment comprises a spool  28  of an elongate tubular string or coiled tubing  30  attached to a reel  32 . The coiled tubing  30  is generally a very long metal pipe that may be between 1-4 inches in diameter. The coiled tubing  30  is advanced along the wellbore  20  using an injector head  34 . A bottom hole assembly  36  may be attached to a terminal end  38  of the coiled tubing  30 . A drill bit  40  is attached to the bottom hole assembly  36  within the wellbore  20 , in  FIG. 2 . During operation, fluid may be pumped down the coiled tubing  30  and exit the drill bit  40  in order to flow into the wellbore  20 . 
     Turning now to  FIGS. 3-5 , a circulation sub  42  is shown. The circulation sub  42  may be one of the downhole tools included in the bottom hole assembly  22  or  36  shown in  FIGS. 1-2 . The circulation sub  42  directs fluid from the drill string  14  or coiled tubing  30  to flow into the wellbore  20  up-hole from the drill bit  16  or  40 . This helps increase circulation within the wellbore  20  if circulation has been decreased or lost. 
     The sub  42  is activated by a single ball  44  and is deactivated by controlling the fluid pressure exerted on the same ball  44 . When activated, fluid flowing through the drill string  14  or coiled tubing  30  exits the sub  42  and flows into the wellbore  20 . When deactivated, fluid will flow completely through the sub  42  towards the drill bit  16  or  40 . The ball  44  is preferably solid and made of nylon, but can be made out of any material that is capable of activating and deactivating the sub  42 . The sub  42  may be activated as many times as needed by sending additional balls  44  down the drill string  14  or coiled tubing  30 . 
     The circulation sub  42  comprises an elongate outer member  46  having a longitudinal internal bore  48  extending therethrough. A threaded pin and box end (not shown) may be formed on opposite ends of the sub  42  so that the sub may be incorporated into the bottom hole assembly  22  or  36 . 
     At least one exit port  50  is formed in the wall of the outer member  46  proximate its top end  52 . The exit port  50  interconnects the internal bore  48  and an outer surface of the outer member  46 . Two exit ports  50  are shown in  FIGS. 3-5 ; however, the outer member  46  may comprise more than two exit ports, if desired. 
     An elongate inner member  54  is disposed within the internal bore  48  of the outer member  46 . The inner member  54  is movable relative to the outer member  46 , and has a longitudinal internal channel  56  extending therethrough. The channel  56  opens at a first surface  58  and an opposite second surface  60  of the inner member  54 . The channel  56  tapers inwardly proximate its midsection to form a narrowed section  62 . The narrowed section  62  terminates at a nozzle  64 . The channel  56  is widened again below the nozzle  64 . 
     The nozzle  64  has a smaller diameter than the ball  44 . The nozzle  64  tapers inwardly to form a funnel. Alternatively, the nozzle  64  may just comprise a round spout. As described later herein, the ball  44  may seat on the nozzle  64  to block fluid flow within the sub  42 . Extrusion of the ball  44  through the nozzle  64  allows fluid to again flow through the sub  42  towards the drill bit  16  or  40 . 
     In one embodiment, the diameter of the nozzle  64  may only be slightly larger than the diameter of the ball  44  so that the ball is not deformed when it is extruded through the nozzle  64 . This allows the ball  44 , if desired, to activate a second downhole tool positioned below the sub  42  in the bottom hole assembly  22  or  36 . The ball  44  may also deform under high pressure in some embodiments. 
     In another embodiment, the diameter of the nozzle  64  may be decreased, as desired, to control the pressure required to extrude the ball  44  through the nozzle  64 . For example, the smaller the diameter of the nozzle  64 , the more pressure required to extrude the ball  44 . This allows the operator to pump a higher rate of fluid into the wellbore  20  before extruding the ball  44  from the sub  42 . When the ball  44  is extruded, fluid pressure within the sub  42  is decreased. As described later herein, this decrease of fluid pressure may deactivate the sub  42 . 
     The rate at which the ball  44  is extruded through the nozzle  64  may also be controlled by varying the strength and size of the ball  44 . Preferably, the ball  44  is configured and the nozzle  64  is sized such that the ball  44  is extruded when the fluid pressure within the sub  42  reaches about 1,200 psi. 
     A spring  66  is positioned within the internal bore  48  of the outer member  46  below the second surface  60  of the inner member  54 . Downward movement of the inner member  54  compresses the spring  66 . Fluid flowing through the sub  42  enters the internal bore  48 , passes through the channel  56 , the center of the spring  66 , and out a bottom end  68  of the sub  42 . 
     A plurality of locking members  70  are supported by the inner member  54 . The locking members  70  are positioned above the nozzle  64  and adjacent the tapered and narrowed section  62  of the channel  56 . The locking members  70  releasably maintain the inner and outer members  54  and  46  in a longitudinally fixed relationship. Two locking members  70  are shown in  FIGS. 3-5 ; however, the sub  42  may only have one locking member  70  or more than two locking members, if desired. The locking members  70  comprise an elongate arm  72  attached to a catch member  74  via a horizontal pin  76 . 
     An elongate slot  78  is formed in the outer wall of the inner member  54  that opens towards the inner surface of the outer member  46 . The arm  72  of the locking member  70  is positioned vertically within the slot  78 . The pin  76  is also positioned within the slot  78 . The catch member  74  is supported horizontally within the inner member  54  and extends between the channel  56  and the slot  78 . A portion of the catch member  74  extends into the channel  56 . 
     An ear  80  is formed at the end of the arms  72  opposite the end that connects with the catch member  74 . The ear  80  shown in  FIGS. 3-5  is a square-shaped projection on the end of the arm  72 . However, the ear  80  may be formed of other shapes, if needed. The ear  80  may be positioned within a groove  82  formed in the wall of the inner member  54 . The groove  82  opens towards a centerline of the outer member  46 . As shown in  FIGS. 3-5 , the outer member  46  may have a single corresponding groove  82  for each locking member  70 . Alternatively, the outer member  46  may have an endless annular groove that each of the ears  80  is positioned within. 
     A hollow sleeve  84  having a series of openings  86  is shown positioned above the inner member  54  in  FIG. 5 . The sleeve  84  is positioned within the internal bore  48 . The openings  86  open into the internal bore  48 . The sleeve  84  may be attached to the first surface  58  of the inner member  54  or may be integral with the inner member. 
     With reference to  FIG. 3 , the sub  42  is shown in the locked position. When in the locked position, the inner member  54  is locked in place within the outer member  46 . The inner member  54  is locked in place because the ears  80  are positioned within the grooves  82 . The catch members  74  are also partially extended into the channel  56  in the locked position, and the wall of the inner member  54  seals fluid from entering the exit ports  50 . The exit ports  50  are not in fluid communication with the internal bore  48  of the sub  42  when in the locked position. 
     In operation, an operator at the ground surface  18  ( FIG. 1 ) may lower or pump a ball  44  down the drill string  14  or coiled tubing  30  along with the fluid to activate the sub  42 . As shown in  FIG. 3 , the ball  44  will enter the sub  42  through a top end  52  of the outer member  46  and flow into the opening of the channel  56  at the first surface  58  of the inner member  54 . Once in the channel  56 , the ball  44  can move the sub  42  to the intermediate position. 
     With reference to  FIG. 4 , the sub  42  is shown in the intermediate position. When in the intermediate position, the inner member  54  is unlocked from the outer member  46 , but the exit ports  50  are still sealed closed by the wall of the inner member  54 . 
     In operation, when the ball  44  enters the channel  56 , it will flow into the narrowed section  62  of the channel  56  where it will engage with the catch members  74 . The ball  44  will exert a downward force on the catch members  74 , causing them to pull the arms  72  towards a centerline of the outer body  46 . This causes the ears  80  to retract out from the grooves  82  and unlock the inner member  54  from the outer member  46 . 
     While the ball  44  is engaged with the catch members  74 , the ball will disrupt the flow of fluid through the sub  42 . This will cause fluid pressure to build within the channel  56  on the backside of the ball  44 . The increased fluid pressure within the channel will force the inner member  54  to move downward within the internal bore  48 . 
     Downward movement of the inner member  54  will pull the arms  72  away from the grooves  82 , and compress the spring  66 . Downward movement of the inner member  54  will also start to move the inner member  54  into an open position. 
     With reference to  FIG. 5 , the sub  42  is shown in the open position. When in the open position, the exit ports  50  are in fluid communication with the internal bore  48  and fluid is permitted to exit the sub  42 . 
     In operation, the fluid pressure will push the ball  44  past the catch members  74  and seat the ball  44  on the nozzle  64 . The ball  44  will block all or almost all fluid from flowing through the channel  56 . This will increase fluid pressure within the channel  56  and cause the inner member  54  to move farther downward within the internal bore  48 , further compressing the spring  66 . The downward movement of the inner member  54  will also pull the arms  72  farther away from the grooves  82 . 
     As the inner member  54  moves downward, it pulls the sleeve  84  and openings  86  in-line with the exit ports  50 , to position the sub  42  in the open position. Fluid flowing through the drill string  14  or coiled tubing  30  and into the sleeve  84  may pass through the openings  86  and exit the sub  42  through the exit ports  50 . Fluid exiting the sub  42  will flow into the wellbore  20  and increase circulation within the wellbore. 
     The ball  44  is shown seated on the nozzle  64  in  FIG. 5 . However, the inner member  54  may move downward far enough such that it is in the open position before the ball  44  becomes seated on the nozzle  64 . For example, the inner member  54  may move into the open position while the ball  44  is still engaged with the catches  74 . 
     After circulation has been increased within the wellbore  20  as desired, an operator at the ground surface  18  ( FIG. 1 ) may decide to deactivate the sub  42 . To do this, the operator may decrease the rate of fluid flowing into the sub  42  or stop fluid from flowing into the sub  42  altogether. This will decrease pressure within the sub  42  and permit the spring  66  to relax. 
     As the spring  66  relaxes, it pushes the inner member  54  upwards within internal bore  48 . Upward movement of the inner member  54  will move the locking members  70  towards the grooves  82 . Because the ball  44  is positioned below the catch members  74 , the ball  44  is no longer forcing the catch members  74  to pull the arms  72  towards the centerline of the outer body  46 . This allows the ears  80  to be supported against the inner surface of the outer member  46 , as shown in  FIG. 5 . Due to this, as the inner member  54  moves the locking members  70  upwards, the ears  80  will re-enter the grooves  82  upon reaching them. 
     Upward movement of the inner member  54  will also push the sleeve  84  away from the exit ports  50 , and the wall of the inner member  54  will seal the exit ports  50  closed. Once the exit ports  50  are sealed, fluid will continue to flow through the sub  42  towards the drill bit  16  or  40 . 
     Once the inner member  54  has returned to the locked position, fluid may be increased within the sub  42  to extrude the ball  44  through the nozzle  64 . This is done by increasing the fluid pressure within in the sub  42  until the ball  44  can no longer withstand the pressure. When this occurs, the ball  44  will be forced through the nozzle  64  and continue through the channel  56  and the center of the spring  66  until it exits the bottom end  68  of the sub  42 . The sub  42  is not reactivated because the catch members  74  prevent the ball  44  from moving upward within the sub. The locking elements  70  may only be disengaged from the locked position in response to downward, but not upward, pressure from the ball  44 . 
     The sub  42  may also be deactivated by extruding the ball  44  prior to moving the inner member  54  to the locked position. To do this, the operator will increase the fluid pressure within the sub  42  while the inner member  54  is still in the open position. Fluid pressure is increased until the ball  44  is extruded through the nozzle  64 . After the ball  44  is extruded, the fluid pressure within the sub  42  will decrease, allowing the spring  66  to relax and the inner member  54  to move back to the locked position. 
     Changes may be made in the construction, operation and arrangement of the various parts, elements, steps and procedures described herein without departing from the spirit and scope of the invention as described in the following claims.