WO2008057654A2 - Cutter assembly - Google Patents
Cutter assembly Download PDFInfo
- Publication number
- WO2008057654A2 WO2008057654A2 PCT/US2007/078487 US2007078487W WO2008057654A2 WO 2008057654 A2 WO2008057654 A2 WO 2008057654A2 US 2007078487 W US2007078487 W US 2007078487W WO 2008057654 A2 WO2008057654 A2 WO 2008057654A2
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- cutter module
- piston
- telescoping
- tubing
- shear blade
- Prior art date
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B29/00—Cutting or destroying pipes, packers, plugs, or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
- E21B33/061—Ram-type blow-out preventers, e.g. with pivoting rams
- E21B33/062—Ram-type blow-out preventers, e.g. with pivoting rams with sliding rams
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/06—Blow-out preventers, i.e. apparatus closing around a drill pipe, e.g. annular blow-out preventers
- E21B33/061—Ram-type blow-out preventers, e.g. with pivoting rams
- E21B33/062—Ram-type blow-out preventers, e.g. with pivoting rams with sliding rams
- E21B33/063—Ram-type blow-out preventers, e.g. with pivoting rams with sliding rams for shearing drill pipes
Definitions
- the invention relates generally to a cutter assembly.
- Offshore systems which are employed in relatively deep water for well operations generally include a riser which connects a surface vessel'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.
- 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.
- the safety shut-in system is first used to sever the coiled tubing.
- a ball valve performs both the function of severing the coiled tubing and the function of shutting off flow.
- a cutter module includes a piston and a shear blade.
- the piston includes at least two movable telescoping elements that are adapted to expand the piston from a retracted length to an expanded length.
- the shear blade is connected to the piston to sever a tubing in response to the piston expanding from the retracted length to the expanded length.
- the shear blade has a cutting edge that has a radius greater than 0.01 inches.
- an apparatus in another embodiment, includes differently- sized spacers and a cutter module assembly that includes opposable shear blades that are adapted to sever a tubing.
- the spacers are adapted to establish different cutting offsets between the shear blades.
- FIG. 1 illustrates an offshore system with a subsea tree having an embodiment of the cutter module of the present invention.
- FIG. 2 illustrates a subsea system with a subsea tree having an embodiment of the cutter module of the present invention.
- FIG. 3 shows an embodiment of the cutter module of the present invention with its blades in their open position.
- Fig. 4 illustrates an embodiment of the cutter module housed within a subsea tree and with its cutting blades retracted.
- 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 cutter module having telescoping pistons. Attorney Docket No. 69.5715
- Fig. 8 provides a side view of an embodiment of the cutter module having telescoping pistons.
- Fig. 9 illustrates an embodiment of the cutter module wherein the cutter module is located below the ball valve.
- Fig. 10 is a schematic diagram of a cutter module assembly with its blades retracted according to an embodiment of the invention.
- Fig. 11 is a more detailed view of a shear blade of a cutter module of Fig. 10 according to an embodiment of the invention.
- Fig. 12 is a more detailed view of a small piston element and associated components of the cutter module of Fig. 10 according to an embodiment of the invention.
- Fig. 13 is a perspective view of the shear blade according an embodiment of the invention.
- Fig. 14 is a cross-sectional view taken along line 14-14 of Fig. 13 according to an embodiment of the invention.
- 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.
- 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 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 may be supported by a fluted hanger 44 or may alternatively be secured to the wellhead 24 with a tubing hanger running tool.
- 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.
- the subsea tree 40 further comprises a cutter module 56 having opposing shear blades 58.
- the cutter 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 cutter 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 cutter 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 Attorney Docket No. 69.5715
- 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.
- 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 may be supported by a fluted hanger 44 or may be secured to the wellhead 24 with a tubing hanger running tool.
- 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.
- the cutter module 56 Housed within the subsea tree 40 is an embodiment of the cutter module 56 of the present invention.
- the cutter module 56 is located below the valve assembly 46 and is shown in Figure 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 cutter module 56 are activated to sever the coiled tubing prior to the well being shut-in,
- Figure 3 shows an embodiment of the cutter module 56 of the present invention with its blades 58 in their open position.
- An intervention tool 60 is lowered through the cutter 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 cutter module 56.
- One or more pressure ports 72 are located in the outer wall 70 of the cutter module 56 and enable communication of fluid (e.g., gas, hydraulic, etc.) pressure via control lines (not shown) into the pressure chamber 68.
- fluid e.g., gas, hydraulic, etc.
- the pressure port(s) 72 are depicted in Fig. 3 as being located on the side of the cutter module 56. However, in other embodiments of the invention, the pressure port(s) 72 may be located on the top surface of the cutter module 56, as little or no space may be available on the side of the cutter module 56 for the pressure port(s) 72. More specifically, in these embodiments of the invention in which the pressure port(s) 72 are located at the top surface of the cutter module 56, the pressure port(s) 72 are in communication with the pressure chamber 62 via passageways that are formed in the outer wall 70.
- 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 shear the coiled tubing 62 running within.
- 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.
- the pistons 64 and blades 58 can be returned to their open state by pressurizing alternate control lines.
- Figure 4 illustrates an embodiment of the cutter module 56 with the cutting blades 58 retracted.
- the cutter module 56 is housed within a subsea tree 40 that includes a valve assembly 46 having a ball valve 52.
- the cutter module 56 is located below the ball valve 52.
- the cutting blades 58 act to sever any coiled tubing located within the cutter 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 cutter 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's labs, the efficiency of a Attorney Docket No. 69.5715
- cutting large diameter coiled tubing with ball valves can require the coiled tubing to be subjected to a large amount of tension.
- the cutter module 56 of the present invention can cut larger diameter coiled tubing in the absence of tension.
- the blades 58 of the cutter 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 Figures 5 and 6.
- the cutting surface 74 has a V-shaped geometry that acts to prevent the collapse of the coiled tubing being cut.
- 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.
- any number of blade geometries can be used to advantage to sever without collapsing the coiled tubing.
- most shapes, other than flat blade ends, will accomplish the same.
- the cutter 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.
- FIG. 7 An embodiment of the telescoping pistons 76 is illustrated in Figures 7 and 8.
- Figure 7 provides a top view of the telescoping piston 76 and
- Figure 8 provides a side view.
- the telescoping pistons 76 utilize multiple piston layers and a cutting blade 58.
- the cutting surface 74 of the cutting blade 58 is a V-shaped geometry.
- a curved radii or other applicable geometry can be used to advantage.
- the cutter 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 Attorney Docket No. 69.5715
- the telescoping pistons 76 expand until they overlap and the blades 58 shear any material running between them. To allow for the overlap, the blades 58 have material removed from specific areas to accommodate the opposite blade geometry.
- hollow slots 78 are provided on the face of the pistons 76 above one of the blades 58 and below the mating blade 58.
- 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.
- the cutter 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.
- the vessel 18 can return to the well site and the marine riser 32 can be re-connected to the blowout preventer stack 22.
- FIG. 9 Another embodiment of the present invention is shown in Figure 9.
- the cutter module 56 is located above the flapper valve 50 and the ball valve 52. As such, this embodiment is useful in vertical wells.
- 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.
- the cutter 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.
- 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.
- a cutter module assembly 100 may be installed in place of the above-described cutter modules 56 or 76 in a subsea string or tree, such as the subsea tree 40. In other embodiments of the invention, the cutter module assembly 100 may be used in a subterranean well.
- a longitudinal axis 110 of the cutter module 100 is generally aligned with the longitudinal axis of the subsea tree 40 where the cutter module assembly 100 is installed.
- the cutter module assembly 100 includes two opposing cutter modules 115A and 115B, each of which has a similar design and includes a telescoping piston.
- each of the telescoping pistons extend (each from a length of approximately five inches to a length of approximately nine inches, for example) to correspondingly extend two opposing cutter blades, or shear blades 160, for purposes of shearing a tubing that extends through a central passageway 102 of the cutter module assembly 100.
- the shear blades 160 may be curved about the longitudinal axis 1 10 for purposes of guiding the tubing to be cut into the shear blades 160.
- the cutter module assembly 100 has certain features to prevent breakage and/or damage that may otherwise occur to cutter blades in connection with cutting a tubing.
- each shear blade 160 is made of S53 stainless steel, which is a high strength, high hardness stainless steel that is significantly ductile.
- S53 stainless steel allows the shear blade 160 to perform multiple cuts with significantly little wear or deformation.
- the shear blade 160 may have a general V-shaped cross- sectional profile, which forces cut tubing pieces apart.
- the shear blade 160 may also have a cutting edge 210, which is purposefully rounded.
- a radius R of the cutting edge 210 may be at least 0.01 inches and may be 0.06 inches (as a more specific example). Other radii are possible and are within the scope of the appended claims.
- the radius R is small enough so that the tubing is cut, instead of being collapsed.
- the radius R is kept sufficiently large, however, to prevent chips of the shear Attorney Docket No. 69.5715
- the rounded shape of the cutting edge 210 improves the distribution of stresses within the shear blade 160. More specifically, the rounded profile of the cutting edge 210 prevents high stress along the cutting edge 210, which may occur in connection with a sharper cutting profile.
- the cutter module assembly 100 has additional features directed to preventing breakage of the shear blades 160.
- the cutter modules 115A and 115B are disposed in a pressure housing 120 of the cutter module assembly 100.
- the central passageway 102 extends through the housing 120 to form a segment of the overall central passageway of the subsea tree 40.
- the housing 120 includes radially-disposed openings, or pockets 122, which receive the cutter modules 115A and 115B.
- the housing 120 may be made of alloy 718 material.
- the cutter module 115A is described below, with it being understood that the cutter module 115B has a similar design, in accordance with some embodiments of the invention.
- the telescoping piston of the cutter module 115A is formed from two piston layers in accordance with some embodiments of the invention, although the telescoping piston may be formed from more than two piston layers in accordance with other embodiments of the invention.
- the piston layers include a small piston element 140 (forming one piston layer), which is disposed inside an inner cylinder 132 of a large piston element 130 (forming another piston layer). O-rings may be used to form a seal between the small 140 and large 130 piston elements.
- the small piston element 140 includes a piston head 230 which has an upper surface 231 that develops a force for driving the element 140 when fluid pressure is applied to activate the cutter module 115 A.
- the piston head 230 is concentric with the inner cylinder 132 of the large piston element 130, is closely sized with the diameter of the inner cylinder 132 and is generally configured to operate within the inner cylinder 132.
- the small piston element 140 also includes a stem 236 that radially extends from the piston head 230 through an opening 131 (see Fig. 10) of the Attorney Docket No. 69.5715
- o -rings may form seals between the outer surface of piston stem 236 and the opening 131.
- the end of the stem 236 farthest away from the piston head 230 includes an opening 238 that is concentric with the stem 236 for purposes of connecting the small piston element 140 to the shear blade 160.
- the shear blade 160 may have a shaft 142 (see Fig. 11), and the shaft 142 may contain outer threads which engage corresponding threads that line the opening 238.
- the small piston element 140 may be made of alloy 718 material, in accordance with some embodiments of the invention, and its piston head 230 may include a profile 232 (see Fig. 12) that facilitates removal of the small piston element 140 (and attached to shear blade 160) during disassembly of the cutter module 115 A, as further discussed below.
- the small piston element 140 translates and transfers hydraulic force into the shear blade 160 during a cutting operation.
- the large piston element 130 in accordance with some embodiments of the invention, is also configured to move in response to pressure that is applied to activate the cutting module 115A.
- the large piston element 130 is generally disposed in the pocket 122 of the housing 120 and in general, circumscribes the small piston element 140.
- a piston cap 124 closes off the otherwise exposed opening of the pocket 122.
- the pocket 122 and cap 124 form a piston chamber in which the large 130 and small 140 piston elements operate.
- the piston cap 124 radially extends into the pocket 122 such that a cylindrical wall 125 of the piston cap 124 extends between a piston head 131 of the large piston element 130 and the inner wall (of the housing 120) that defines the pocket 122.
- One or more o-rings may form seals between the piston head 131 and the wall 125 of the piston cap 124. Additionally, o-rings may form seals between the piston cap 124 and the inner wall of the pocket 122.
- the piston cap 124 may be formed from alloy 718 material, in accordance with some embodiments of the invention. Attorney Docket No. 69.5715
- the cutter housing 120 includes an opening 123 between the pocket 122 and central passageway 120 through which the large piston element 130 extends when the cutter module 115A is activated.
- O-rings may form a seal between the housing 122 and the outer surface of the large piston element 130 at the opening 123.
- the large piston element 130 may move radially inwardly in response to pressure; and the movement of the large piston element 130 also carries the small piston element 140, which further extends (due to the telescoping arrangement) with the attached shear blade 160.
- the large piston element 130 may be formed of alloy 718 material, in accordance with some embodiments of the invention.
- the cutter module 115 A includes at least one passageway 126 for purposes of communicating fluid pressure to the large 130 and small 140 piston elements. More specifically, in accordance with some embodiments of the invention, the passageway(s) 126 are routed through the piston cap 124, and o-rings may straddle the passageway (s) 126 for purposes of sealing off the passageway(s). The passageway(s) 126 deliver pressure to the outer surface of the piston heads of the large piston elements 130.
- the large piston element 130 may also include one or more passageways 133 for purposes of resetting the position of the telescoping piston when the driving pressure is released. More specifically, in accordance with some embodiments of the invention, the passageway (s) 133 extend from a region below the piston head of the large piston element 130 to a region 132 (in the inner cylinder) below the piston head of the small piston element 140. Therefore, after the driving pressure on the telescoping piston is released, the passageway(s) 133 communicate pressure to restore the small piston element 140 back to its recessed position.
- the cutter module assembly 100 may have one or more additional features to limit or prevent breakage of the shear blades 160, in accordance with embodiments of the invention.
- the cutter module 115A includes a piston spacer 150, which may generally be, for example, a ring, which circumscribes the stem 236 (see also Fig. 12) of the small piston element 140.
- a piston spacer 150 which may generally be, for example, a ring, which circumscribes the stem 236 (see also Fig. 12) of the small piston element 140.
- the piston spacer 150 limits the extension of the shear blade 160 during operation of the cutter module 115 A. More specifically, the spacer 150 limits the travel of the small piston element 140 with respect to the large piston element 130 during a cutting operation, as the spacer 150 establishes a fixed offset between the bottom 233 (see Fig. 12) of the piston head 230 of the small piston element 140 and the otherwise contacting surface 161 (see Fig. 10) of the large piston element 130. Due to this travel limitation, a minimum offset, or gap, between the opposing shear blades 160 may be controlled based on the size of the tubing to be cut.
- a set, or kit, of differently-sized (i.e., different thicknesses) piston spacers 150 may be provided with the cutter module assembly 100 so that the appropriate spacer 150 (i.e., the piston spacer 150 having the appropriate thickness) may be selected and installed in the cutter modules 115A and 115B based on one or more characteristic(s) (size and/or ductility of the tubing, as examples) of the tubing to be cut.
- the same thickness spacer 150 may be installed in each cutter module 115A and 115B for a particular cutting application.
- the appropriate thicknesses for the piston spacers 150 may be determined by test cuts using job-specific tubing samples, for example. In this regard, by taking measurements off of a successfully cut tubing, the measurements may be used to select the correct spacer thickness, so that the appropriately sized set of spacers 150 (i.e., one for each cutter module 115 A, 115B) may be selected for the tubing that may need to be cut downhole.
- the piston spacers 150 may be formed from 316 stainless steel, in accordance with some embodiments of the invention. Attorney Docket No. 69.5715
- the cutter module 115A may include a retainer ring 138 (see Fig. 12) for purposes of limiting the movement of the small piston element 140 (and its attached shear blade 160) during the disassembly of the cutter module 115 A.
- the small piston element 140 when the cutter module 115A is disassembled and the piston cap 124 is removed, the small piston element 140 must be pulled with significant force to remove the entire small piston element 140, large piston element 130, and shear blade subassembly (the shear blade 160, shaft 140).
- the retainer ring 138 prevents the shear blade 160 from making contact with the large piston element 130 during this operation thus protecting the shear blade 160 from being damaged or broken.
- the retainer ring 138 forms a stop to hold the small piston element 140 within the large piston element 130. More specifically, in accordance with some embodiments of the invention, the small piston element 140 includes an annular shoulder 250 (see Fig. 12) that is configured to contact an inner annular portion of the retainer ring 138. An outer annular portion 260 of the retainer ring 138 extends into a corresponding annular groove, which is formed in the inner wall of the large piston element's inner cylinder 132.
- the retainer ring 138 is attached to the large piston element 130 to establish farthest point of retraction for the small piston element 140.
- a tool may be used to engage the profile 232 of the small piston assembly 140 before the retainer ring 138 is removed to allow extraction of the small piston element 140 and attached shear blade 160.
- the retainer ring 138 may be formed from 300 series stainless steel, in accordance with some embodiments of the invention.
- guide slots 171 may be machined into the cutter housing 122 for purposes of guiding and supporting the shear blades 160 as the shear blades 160 extend and retract.
- the guide slots 171 keep the shear blades 160 properly aligned for cutting, normal to the bore.
- a blade key 170 formed from alloy 718 Attorney Docket No. 69.5715
- each guide slot 171 may be assembled inside each guide slot 171 for purposes of providing additional support for the shear blades 160 during their entire open/close cycle.
- the cutter module assembly 100 may also include a bore seal sub 190 that forms a sealed connection (via o- rings, for example) with one end of the cutter assembly housing 122. Additionally, the cutter module assembly 100 may include a turnbuckle coupling 180 (formed from high strength steel, for example) that is used for purposes of connecting the cutter module assembly 100 to the subsea string.
- the turnbuckle coupling 180 provides structural support for the cutter module assembly 100, carries any load that hangs below the cutter module assembly 100 and may serve as a centralizer when the assembly 100 is run in and out of hole.
- the assembly of the cutter module assembly 100 may further be aided by one or more alignment pins 181, which guide the assembly 100 into alignment with the rest of the string or tree.
- Fig. 13 depicts a perspective view of a shear blade 400 in accordance with some embodiments of the invention.
- Fig. 14 depicts a corresponding cross-sectional view taken along line 14-14 of Fig. 13.
- the shear blade 400 has a cutting surface 414 that has a general curved profile 410, which extends partially around the longitudinal axis of the cutter module assembly.
- the cutting surface 414 is also sloped with respect to the cutter module assembly's longitudinal axis to form a corresponding V-shaped cross section.
- a cutting edge 418 of the shear blade 400 has a rounded radius, such as a radius of at least 0.01 inches (0.06 inches, for example), as depicted in Fig. 11.
- the shear blade 400 may include a shaft 402, which includes a threaded receptacle 420 for purposes of attaching the shear blade 400 to the small piston element 40. It is noted that the shear blade 400 is one out of many possible embodiments, which may fall under the scope of the appended claims.
- the cutter housing 120 may include an annular groove on its outer surface for purposes of lifting and handling the cutter module assembly 100 to assemble the assembly 100 in a tree.
- the annular groove permits clamps, which have corresponding shoulders, to latch on to the cutter module assembly 100 so that the assembly 100 does not slip during operation.
- the cutter module assembly 100 may be shipped horizontally and used vertically.
- the handling gear rotates the test tree from horizontal to vertical, which may be a significant operation because of the size and weight of the test tree (a size of approximately 20,000 pounds and 20 + feet as an example).
Abstract
Description
Claims
Priority Applications (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
BRPI0717865-4A BRPI0717865A2 (en) | 2006-11-02 | 2007-09-14 | CUTTING MODULE FOR SECTIONING A Duct IN A WELL, METHOD FOR SECTIONING A Duct IN A WELL, SYSTEM, METHOD, AND APPARATUS |
GB0907312A GB2456702B (en) | 2006-11-02 | 2007-09-14 | Cutter assembly |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US11/555,713 US20080105436A1 (en) | 2006-11-02 | 2006-11-02 | Cutter Assembly |
US11/555,713 | 2006-11-02 |
Publications (2)
Publication Number | Publication Date |
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WO2008057654A2 true WO2008057654A2 (en) | 2008-05-15 |
WO2008057654A3 WO2008057654A3 (en) | 2008-10-09 |
Family
ID=39226921
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
PCT/US2007/078487 WO2008057654A2 (en) | 2006-11-02 | 2007-09-14 | Cutter assembly |
Country Status (4)
Country | Link |
---|---|
US (1) | US20080105436A1 (en) |
BR (1) | BRPI0717865A2 (en) |
GB (2) | GB2456702B (en) |
WO (1) | WO2008057654A2 (en) |
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US8061429B2 (en) | 2008-12-30 | 2011-11-22 | Schlumberger Technology Corporation | Systems and methods for downhole completions |
US8347967B2 (en) | 2008-04-18 | 2013-01-08 | Sclumberger Technology Corporation | Subsea tree safety control system |
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EP2294278A2 (en) | 2008-05-09 | 2011-03-16 | Gulfstream Services, Inc. | Oil well plug and abandonment method |
US8127858B2 (en) * | 2008-12-18 | 2012-03-06 | Baker Hughes Incorporated | Open-hole anchor for whipstock system |
US8517112B2 (en) * | 2009-04-30 | 2013-08-27 | Schlumberger Technology Corporation | System and method for subsea control and monitoring |
US8336629B2 (en) * | 2009-10-02 | 2012-12-25 | Schlumberger Technology Corporation | Method and system for running subsea test tree and control system without conventional umbilical |
US8464785B2 (en) * | 2011-06-14 | 2013-06-18 | Hydril Usa Manufacturing Llc | Pipe guide arms for blind shear rams |
US20140209314A1 (en) * | 2013-01-28 | 2014-07-31 | Schlumberger Technology Corporation | Shear and seal system for subsea applications |
RU2596022C2 (en) * | 2013-03-13 | 2016-08-27 | Александр Васильевич Торговецкий | Device for covering underwater flowing oil-gas wells at unauthorised blowout |
GB201614712D0 (en) * | 2016-08-31 | 2016-10-12 | Enovate Systems Ltd | Improved shear blade |
USD973734S1 (en) * | 2019-08-06 | 2022-12-27 | Nxl Technologies Inc. | Blind shear |
BR102020001435A2 (en) * | 2020-01-23 | 2021-08-03 | Halliburton Energy Services, Inc. | METHOD TO DISSIPATE FORCE WITHIN A PIPE COLUMN, FORCE DISSIPATION SYSTEM, AND, WELLBOE ENVIRONMENT |
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US8347967B2 (en) | 2008-04-18 | 2013-01-08 | Sclumberger Technology Corporation | Subsea tree safety control system |
US8061429B2 (en) | 2008-12-30 | 2011-11-22 | Schlumberger Technology Corporation | Systems and methods for downhole completions |
Also Published As
Publication number | Publication date |
---|---|
GB2456702A (en) | 2009-07-29 |
WO2008057654A3 (en) | 2008-10-09 |
GB2476901A (en) | 2011-07-13 |
US20080105436A1 (en) | 2008-05-08 |
BRPI0717865A2 (en) | 2013-11-05 |
GB0907312D0 (en) | 2009-06-10 |
GB2456702B (en) | 2011-11-23 |
GB201106661D0 (en) | 2011-06-01 |
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