Abstract:
A cutting module to sever a tubing in a well includes a piston and shear blade. The piston includes at least two moveable telescoping elements, which are adapted to expand the first piston from a retracted length to an expanded length. The shear blade is connected to the piston to sever the tubing in response to the piston expanding from the retracted length to the expanded length. The cutting module may be located below a safety valve in the well.

Description:
This application is a continuation of U.S. patent application Ser. No. 10/321,217, now U.S. Pat. No. 7,086,467 entitled “COILED TUBING CUTTER,” which was filed on Dec. 17, 2002 , and is hereby incorporated by reference in its entirety. 

   BACKGROUND 
   The present invention relates generally to safety shut-in systems employed during testing or other operations in subsea wells. More specifically, the invention relates to a coiled tubing cutter for use with a safety shut-in system in a subsea well. 
   Offshore systems which are employed in relatively deep water for well operations generally include a riser which connects a surface vessel&#39;s equipment to a blowout preventer stack on a subsea wellhead. The marine riser provides a conduit through which tools and fluid can be communicated between the surface vessel and the subsea well. 
   Offshore systems which are employed for well testing operations also typically include a safety shut-in system which automatically prevents fluid communication between the well and the surface vessel in the event of an emergency, such as loss of vessel positioning capability. Typically, the safety shut-in system includes a subsea test tree which is landed inside the blowout preventer stack on a pipe string. 
   The subsea test tree generally includes a valve portion which has one or more normally closed valves that can automatically shut-in the well. The subsea test tree also includes a latch portion which enables the portion of the pipe string above the subsea test tree to be disconnected from the subsea test tree. 
   If an emergency condition arises during the deployment of tools on coiled tubing, for example, the safety shut-in system is first used to sever the coiled tubing. In a typical safety shut-in system, a ball valve performs both the function of severing the coiled tubing and the function of shutting off flow. 
   Although somewhat effective, the use of ball valves to sever the coiled tubing has proven difficult with larger sizes of coiled tubing. Additionally, use of the ball valves to perform cutting operations can have detrimental sealing effects on the sealing surfaces of the valve. Specifically, the sealing surfaces can become scarred, reducing the sealing efficiency. 
   There exists, therefore, a need for an efficient coiled tubing cutter. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  illustrates an offshore system with a subsea tree having an embodiment of the cutting module of the present invention. 
       FIG. 2  illustrates a subsea system with a subsea tree having an embodiment of the cutting module of the present invention. 
       FIG. 3  shows an embodiment of the cutting module of the present invention with its blades in their open position. 
       FIG. 4  illustrates an embodiment of the cutting module housed within a subsea tree and with its cutting blades activated. 
       FIG. 5  provides a top view of the V-shaped geometry of one embodiment of the cutting blades. 
       FIG. 6  provides a top view of the curved radii geometry of one embodiment of the cutting blades. 
       FIG. 7  provides a top view of an embodiment of the cutting module having telescoping pistons. 
       FIG. 8  provides a side view of an embodiment of the cutting module having telescoping pistons. 
       FIG. 9  illustrates an embodiment of the cutting module wherein the cutting module is located below the ball valve. 
   

   DETAILED DESCRIPTION 
   It should be clear that the present invention is not limited to use with the particular embodiments of the subsea systems shown, but is equally used to advantage on any other well system in which severing of coiled tubing, wireline, slickline, or other production or communication lines may become necessary. 
   Furthermore, although the invention is primarily described with reference to intervention tools deployed on coiled tubing, it should be understood that the present invention can be used to advantage to sever wireline, slickline, or other production or communication line as necessary. 
   Referring to the drawings wherein like characters are used for like parts throughout the several views,  FIG. 1  depicts a well  10  which traverses a fluid reservoir  12  and an offshore system  14  suitable for testing productivity of the well  10 . The offshore system  14  comprises a surface system  16 , which includes a production vessel  18 , and a subsea system  20 , which includes a blowout preventer stack  22  and a subsea wellhead  24 . 
   The subsea wellhead  24  is fixed to the seafloor  26 , and the blowout preventer stack  22  is mounted on the subsea wellhead  24 . The blowout preventer stack  22  includes ram preventers  28  and annular preventers  30  which may be operated to seal and contain pressure in the well  10 . A marine riser  32  connects the blowout preventer stack  22  to the vessel  18  and provides a passage  34  through which tools and fluid can be communicated between the vessel  18  and the well  10 . In the embodiment shown, the tubing string  36  is located within the marine riser  32  to facilitate the flow of formation fluids from the fluid reservoir  12  to the vessel  18 . 
   The subsea system  20  includes a safety shut-in system  38  which provides automatic shut-in of the well  10  when conditions on the vessel  18  or in the well  10  deviate from preset limits. The safty shut-in system  38  includes a subsea tree  40  that is landed in the blowout preventer stack  22  on the tubing string  36 . A lower portion  42  of the tubing string  36  is supported by a fluted hanger  44 . 
   The subsea tree  40  has a valve assembly  46  and a latch  48 . The valve assembly  46  acts as a master control valve during testing of the well  10 . The valve assembly  46  includes a normally-closed flapper valve  50  and a normally-closed ball valve  52 . The flapper valve  50  and the ball valve  52  may be operated in series. The latch  48  allows an upper portion  54  of the tubing string  36  to be disconnected from the subsea tree  40  if desired. 
   In an embodiment of the present invention, the subsea tree  40  further comprises a cutting module  56  having opposing shear blades  58 . The cutting module  56  is located below the valve assembly  46 . If an emergency condition arises during deployment of intervention tools lowered through the tubing string  36  on coiled tubing, the blades  58  of the cutting module  56  are activated to sever the coiled tubing prior to the well being shut-in. 
     FIG. 2  illustrates a subsea system  20  having an embodiment of the cutting module  56  of the present invention. The subsea system  20  is adapted to facilitate production from a well  10  to an offshore vessel (not shown). The subsea system includes a blowout preventer stack  22 , a subsea wellhead  24 , and a safety shut-in system  38 . The subsea wellhead  24  is fixed to the seafloor  26 , and the blowout preventer stack  22  is mounted on the subsea wellhead  24 . The blowout preventer stack  22  includes ram preventers  28  and annular preventers  30  which may be operated to seal and contain pressure in the well  10 . A marine riser  32  connects the blowout preventer stack  22  to an offshore vessel and provides a passage through which tools and fluid can be communicated between the vessel and the well  10 . In the embodiment shown, the tubing string  36  is located within the marine riser  32  to facilitate the flow of formation fluids from the fluid reservoir to the vessel. 
   The safety shut-in system  38  of the subsea system  20  provides automatic shut-in of the well  10  when conditions on the vessel deviate from preset limits. The safety shut-in system  38  includes a subsea tree  40  that is landed in the blowout preventer stack  22  on the tubing string  36 . A lower portion  42  of the tubing string  36  is supported by a fluted hanger  44 . The subsea tree  40  has a valve assembly  46  and a latch  48 . The valve assembly  46  acts as a master control valve during testing of the well  10 . The valve assembly  46  includes a normally-closed flapper valve  50  and a normally-closed ball valve  52 . The flapper valve  50  and the ball valve  52  may be operated in series. The latch  48  allows an upper portion  54  of the tubing string  36  to be disconnected from the subsea tree  40  if desired. 
   Housed within the subsea tree  40  is an embodiment of the cutting module  56  of the present invention. The cutting module  56  is located below the valve assembly  46  and is shown in  FIG. 2  with its blades  58  in their open position. If an emergency condition arises during deployment of intervention tools lowered through the tubing string  36  on coiled tubing, the blades  58  of the cutting module  56  are activated to sever the coiled tubing prior to the well being shut-in. 
     FIG. 3  shows an embodiment of the cutting module  56  of the present invention with its blades  58  in their open position. An intervention tool  60  is lowered through the cutting module  56  on coiled tubing  62 . 
   The blades  58  are shown in their open position and are affixed to a piston  64  located within a piston housing  66 . A pressure chamber  68  is defined by the piston housing  66  and the outer wall  70  of the cutting module  56 . One or more pressure ports  72  are located in the outer wall  70  of the cutting module  56  and enable communication of fluid (e.g., gas, hydraulic, etc.) pressure via control lines (not shown) into the pressure chamber  68 . 
   To activate the blades  58 , fluid pressure is supplied by the control lines to the one or more pressure ports  72 . The fluid pressure acts to push the pistons  64  toward the coiled tubing  62  until the blades  58  overlap and shear the coiled tubing  62  running within. After the coiled tubing  62  has been cut by the blades  58 , the fluid pressure supplied by the control lines is discontinued and the pressurized pistons  64  and blades  58  return to their open state as a result of the much higher bore pressure existing within the tubing string  36 . 
   In some embodiments, to accommodate the overlap of the blades  58 , hollow slots  78  (shown in hidden lines) are provided in the face of the opposing blades  58 . 
     FIG. 4  illustrates an embodiment of the cutting module  56  with the cutting blades  58  activated. The cutting module  56  is housed within a subsea tree  40  that includes a valve assembly  46  having a ball valve  52 . The cutting module  56  is located below the ball valve  52 . 
   Upon activation by applying pressure to the piston  64 , the cutting blades  58  act to sever any coiled tubing located within the cutting module  56 . After the coiled tubing has been severed and removed from the subsea tree  40 , the ball valve  52  is closed to shut-in the well. 
   The blades  58  utilized by the cutting module  56  are designed specifically for cutting and thus provide a more efficient cut than traditional equipment such as ball valves used to cut coiled tubing. In tests conducted within Schlumberger&#39;s labs, the efficiency of a ball valve in cutting is approximately 20% versus a basic shear approximation. By contrast, the cutting blades  58  of the cutting module  56  have shown an efficiency of over 100%. 
   Additionally, cutting large diameter coiled tubing with ball valves can require the coiled tubing to be subjected to a large amount of tension. By contrast, the cutting module  56  of the present invention can cut larger diameter coiled tubing in the absence of tension. 
   The blades  58  of the cutting module  56  are designed to prevent the collapse of the coiled tubing being cut. As a result, the cut coiled tubing is much easier to fish following the severing process. While any number of blade geometries can be used to advantage by the present invention, for purpose of illustration, two example geometries are shown in  FIGS. 5 and 6 . 
   In the top view illustration of  FIG. 5 , the cutting surface  74  has a V-shaped geometry that acts to prevent the collapse of the coiled tubing being cut. Similarly, in the top view illustration of  FIG. 6 , the cutting surface  74  of the cutting blade  58  has a curved radii that closely matches the diameter of the coiled tubing deployed therebetween. Both geometries act to prevent the collapse of the coiled tubing to enable easier fishing operations. 
   As stated above, any number of blade geometries can be used to advantage to sever without collapsing the coiled tubing. In fact, most shapes, other than flat blade ends, will accomplish the same. 
   In other embodiments the cutting module  56  utilizes telescoping pistons. Due to the limited size in the tubing string  36  within which to hold cutting equipment, the use of telescoping pistons enables greater travel of the pistons, and thus attached blades, than that achievable with traditional pistons. 
   An embodiment of the telescoping pistons  76  is illustrated in  FIGS. 7 and 8 .  FIG. 7  provides a top view of the telescoping piston  76  and  FIG. 8  provides a side view. 
   The telescoping pistons  76  utilize multiple piston layers and a cutting blade  58 . In the embodiment shown, the cutting surface  74  of the cutting blade  58  is a V-shaped geometry. However, it should be understood that a curved radii or other applicable geometry can be used to advantage. 
   The cutting module  56  utilizes two telescoping pistons  76  that lie opposite of each other. Upon pressurization, the piston layers begin their stroke and expand to a length greater than that achievable with a traditional piston. The telescoping pistons  76  expand until they overlap and the blades  58  shear any material running between them. To allow for the overlap, hollow slots  78  are provided on the face of the pistons  76  above one of the blades  58  and below the mating blade  58 . 
   Following the cutting procedure, the supplied pressure is discontinued and the non-pressurized piston layers of the telescoping pistons  76  return to their non-extended positions as a result of the much higher bore pressure within the tubing string. 
   in operation, and with reference to  FIG. 1 , the subsea tree  40  is landed in the blowout preventer stack  22 , comprising ram preventers  28  and annular preventers  30 , on the tubing string  36 . The flapper valve  50  and the ball valve  52  in the subsea tree  40  are open to allow fluid flow from the lower portion  42  of the tubing string  36  to the upper portion  54  of the tubing string  36 . Additionally, the open valves  50 ,  52  allow for tools to be lowered via coiled tubing (or wireline, slickline, communication lines, etc.) through the tubing string  36  to perform intervention operations. 
   In the event of an emergency during an intervention operation, the cutting module  56  is activated to sever the coiled tubing. Once severed, coiled tubing remaining in the upper portion  54  of the tubing string  36  is raised until its severed end clears both the ball valve  52  and the flapper valve  50  of the valve assembly  46 . At this point, the valves  50 ,  52  can be automatically closed to prevent fluid from flowing from the lower portion  42  of the tubing string  36  to the upper portion  54  of the tubing string  36 . Once the valves  50 ,  52  are closed, the latch  48  is released enabling the upper portion  54  of the tubing string  36  to be disconnected from the subsea tree  40  and retrieved to the vessel  18  or raised to a level which will permit the vessel  18  to drive off if necessary. 
   After the emergency situation, the vessel  18  can return to the well site and the marine riser  32  can be re-connected to the blowout preventer stack  22 . The safety shut-in system  38  can be deployed again and the coiled tubing that remains in the lower portion  42  of the tubing string  36  can be retrieved through various fishing operations. 
   It is important to note that the above embodiment is useful in both vertical and horizontal wells. Because the cutting module  56  severs the coiled tubing below the valves  50 ,  52 , the severed portion of the coiled tubing will not interfere with the closing of the valves  50 ,  52 . 
   Another embodiment of the present invention is shown in  FIG. 9 . In this embodiment, the cutting module  56  is located above the flapper valve  50  and the ball valve  52 . As such, this embodiment is useful in vertical wells. 
   In operation, the subsea tree  40  is landed in the blowout preventer stack  22 , comprising ram preventers  28  and annular preventers  30 , on the tubing string  36 . The flapper valve  50  and the ball valve  52  in the subsea tree  40  are open to allow fluid flow from the lower portion  42  of the tubing string  36  to the upper portion  54  of the tubing string  36 . Additionally, the open valves  50 ,  52  allow for tools to be lowered via coiled tubing (or wireline, slickline, communication lines, etc.) through the tubing string  36  to perform intervention operations. 
   In the event of an emergency during an intervention operation, the cutting module  56  is activated to sever the coiled tubing. Once severed, coiled tubing remaining in the lower portion  42  of the tubing string  36  falls within the vertical well until it has cleared both the ball valve  52  and the flapper valve  50  of the valve assembly  46 . At this point, the valves  50 ,  52  can be automatically closed to prevent fluid from flowing from the lower portion  42  of the tubing string  36  to the upper portion  54  of the tubing string  36 . Once the valves  50 ,  52  are closed, the latch  48  is released to enable the upper portion  54  of the tubing string  36  to be disconnected from the subsea tree  40  and retrieved to the vessel (not shown) or raised to a level which will permit the vessel to drive off if necessary. 
   After the emergency situation, the vessel can return to the well site and the marine riser  32  can be re-connected to the blowout preventer stack  22 . The safety shut-in system  38  can be deployed again and the coiled tubing that remains in the lower portion  42  of the tubing string  36  can be retrieved through various fishing operations. 
   While the invention has been described with respect to a limited number of embodiments, those skilled in the art will appreciate numerous variations therefrom without departing from the spirit and scope of the invention.