US20080105436A1

US20080105436A1 - Cutter Assembly

Info

Publication number: US20080105436A1
Application number: US11/555,713
Authority: US
Inventors: Paul Molina; Allyn Pratt; John Yarnold
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2006-11-02
Filing date: 2006-11-02
Publication date: 2008-05-08
Also published as: GB2476901A; BRPI0717865A2; GB2456702B; WO2008057654A3; GB201106661D0; GB0907312D0; WO2008057654A2; GB2456702A

Abstract

A cutter module includes a piston and a shear blade. The piston includes at least two movable telescoping elements that are adapted to expand from a first retracted length to a second expanded length. The shear blade is connected to the first piston to sever a tubing in response to the piston expanding from the retracted length to the second expanded length. The shear blade has a cutting edge that has a radius greater than 0.01 inches.

Description

BACKGROUND

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. 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 tubing cutter.

SUMMARY

In an embodiment of the invention, 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.
In another embodiment of the invention, an apparatus 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.
Advantages and other features of the invention will become apparent from the following description, drawing and claims.

BRIEF DESCRIPTION OF THE DRAWING

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.

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.

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 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.
In an embodiment of the present invention, 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 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 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.
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 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 cutter module 56 are activated to sever the coiled tubing prior to the well being shut-in.
FIG. 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.
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.
To activate, or extend, 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 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. When testing at surface with no bore pressure, the pistons 64 and blades 58 can be returned to their open state by pressurizing alternate control lines.
In some embodiments, to accommodate the retraction of the blades 58, material was removed from the supporting side large piston or piston housing 66. This material was removed from the complete diameter such that rotation of the large piston or piston housing 66 does not affect the cutter blade.
FIG. 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.
Upon activation by applying pressure to the piston 64, 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 ball valve in cutting is approximately 20% versus a basic shear approximation. By contrast, the cutting blades 58 of the cutter 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 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 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 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.
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 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 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, the blades 58 have material removed from specific areas to accommodate the opposite blade geometry. For example, in some embodiments of the invention, 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. When testing at surface with no bore pressure, the pistons 76 and blades 58 may be retracted to their open states by pressuring alternate control lines.
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 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.
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 cutter 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 cutter 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 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.
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.
Referring to FIG. 10, in accordance with some embodiments of the invention, 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. When an activation pressure is concurrently applied to both cutter modules 115A and 115B, 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 110 for purposes of guiding the tubing to be cut into the shear blades 160.
As described below, 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.
More specifically, in accordance with some embodiments of the invention, each shear blade 160 is made of S53 stainless steel, which is a high strength, high hardness stainless steel that is significantly ductile. The use of the S53 stainless steel allows the shear blade 160 to perform multiple cuts with significantly little wear or deformation.
Referring to FIG. 11 in conjunction with FIG. 10, in accordance with some embodiments of the invention, 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. In particular, in accordance with some embodiments of the invention, 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 blade 160 from breaking off during a cut, which may otherwise occur for a sharper cutting edge. Additionally, 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.
Referring back to FIG. 10, the cutter module assembly 100 has additional features directed to preventing breakage of the shear blades 160. Turning to the more specific details, 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. In accordance with some embodiments of the invention, 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. In the specific example that is depicted in FIG. 10, 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.
Referring to FIG. 12 in conjunction with FIG. 10, 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 115A. 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 larger piston element 130. As depicted in FIG. 10, 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. More specifically, in accordance with some embodiments of the invention, 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.
Among the other features of the small piston element 140, 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 115A, as further discussed below.
As can be seen from the preceding description, the small piston element 140 translates and transfers hydraulic force into the shear blade 160 during a cutting operation.
Referring to FIG. 10, 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. As shown in FIG. 10, 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. Thus, the pocket 122 and cap 124 form a piston chamber in which the large 130 and small 140 piston elements operate.
In accordance with some embodiments of the invention, 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.
As depicted in FIG. 10, 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. Thus, 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.
For purposes of actuating the telescoping piston, the cutter module 115A, in accordance with some embodiments of the invention, 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.
Among its other features, 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. For example, as depicted in FIG. 10, in accordance with some 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.
The piston spacer 150, in general, limits the extension of the shear blade 160 during operation of the cutter module 115A. 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.
More specifically, it has been discovered that as the shear blades 160 travel past the point at which the tubing is cut, the blades and tubing may impact into each other, which causes excessive transverse stresses (not present during the actual cutting operation) in the blades 160. These transverse stresses, in turn, may cause the blades 160 to break. Thus, by limiting the travel of the shear blades 160, a successful tubing cut may be achieved, while preventing breakage of the shear blades 160.
Therefore, in accordance with some embodiments of the invention, 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. In accordance with some embodiments of the invention, 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 115A, 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.
Referring to FIG. 12 in conjunction with FIG. 10, among the other features of the cutter module 115A, in accordance with some embodiments of the invention, 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 115A. In this regard, 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.
To prevent premature disengagement of the small piston element 140 from the cutter module 115A, 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.
Thus, when the cutter module 115A is completely assembled, the retainer ring 138 is attached to the large piston element 130 to establish farthest point of retraction for the small piston element 140. When the cutter module 115A is disassembled, 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.
Referring back to FIG. 10, among the other features of the cutter module assembly 100, in accordance with some embodiments of the invention, guide slots 171 (one guide slot 171 being depicted in FIG. 10) 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. In some embodiments of the invention, a blade key 170 (formed from alloy 718 material, for example) 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.
In accordance with some embodiments of the invention, the cutter module assembly 100 may also include a bore seal sub 190 that forms a scaled 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. As can be seen, 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. Referring to FIG. 14, 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. Although not depicted in FIGS. 13 and 14, 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. Among its other features, 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.
Other embodiments are within the scope of the appended claims. For example, in accordance with some embodiments of the invention, the cutter housing 120 (see FIG. 10, for example) 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. Thus, 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).
While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of the invention.

Claims

1. A cutter module to sever a tubing in a well, comprising:

a piston comprising at least two moveable telescoping elements adapted to expand the piston from a retracted length to an expanded length; and

a shear blade connected to the first piston to sever the tubing in response to the piston expanding from the retracted length to the expanded length,

wherein the shear blade has a cutting edge having a radius greater than 0.01 inches.

2. The cutter module of claim 1, wherein the radius of the cutting edge is approximately 0.06 inches.

3. The cutter module of claim 1, wherein the shear blade comprises S53 stainless steel.

4. The cutter module of claim 1, wherein said at least two moveable telescoping elements comprises a first telescoping element and disposed in a second telescoping element, the cutter module further comprises:

a retainer to protect the shear blade and retraction of the cutter pistons and disassembly of the cutter module.

5. The cutter module of claim 4, wherein the retainer comprises a backup mechanism to prevent the first telescoping element from coming out of the second telescoping element if the shear blade breaks.

6. The cutter module of claim 4, wherein the retainer is adapted to prevent the shear blade from contacting the second telescoping element.

7. The cutter module of claim 4, wherein the retainer comprises a ring.

8. The cutter module of claim 1, wherein one of said at least two moveable telescoping elements comprises a first telescoping element that telescopes inside a stationary tubular body and a second telescoping element that telescopes inside the first telescoping element.

9. The cutter module of claim 1, further comprising:

another piston opposable to the first piston;

a second shear blade connected to said another piston,

wherein said another piston is adapted to move in concert with the first piston to cause the first and second shear blades to sever the tubing.

10. The cutter module of claim 1, further comprising:

a housing to contain the shear blade, the housing comprising a slot to guide the shear blade as the blade extends and retracts.

11. A method to sever a tubing in a well, the method comprising:

moving at least two moveable telescoping elements of a first piston to cause the first piston to expand from a first retracted length to a second expanded length; and

driving a first shear blade with the piston to sever the tubing, comprising contacting the tubing with a cutting edge that has a radius greater than 0.01 inches.

12. The method of claim 11, wherein the contacting comprise contacting the tubing with a cutting edge that has a radius of approximately 0.06 inches.

13. The method of claim 11, wherein said at least two movable telescoping elements comprises a first telescoping element disposed to move in a cylinder of a second telescoping element, further comprising:

providing a retainer inside the cylinder to limit motion of the first telescoping element.

14. The method of claim 11, wherein the act of moving comprises:

moving one of said at least two moveable telescoping elements inside a stationary tubular body and moving another of said at least two moveable telescoping elements inside said one of said at least two moveable telescoping elements.

15. The method of claim 11, further comprising:

guiding the shear blade along a slot form in a housing that contains the first shear blade.

16. A system comprising:

a blowout preventer stack adapted to seal and contain pressure in a well, the blowout preventer having a passageway through which a tubular string may extend into the well;

a subsea wellhead;

a safety shut-in system having a valve assembly adapted to control flow and adapted to allow tools to be lowered therethrough on tubing; and

a cutter module adapted to be run into the passageway and adapted to allow tools to be lowered into the passageway on tubing, the cutter module comprising:

a shear blade connected to the piston to sever the tubing in response to the piston expanding from the retracted length to the expanded length, wherein the shear blade has a cutting edge having a radius greater than 0.01 inches.

17. A method comprising:

providing a kit that includes a set of differently-sized spacers and a cutter module assembly having opposable shear blades; and

configuring the spacers to establish different offsets between the shear blades when installed in the cutter module to accommodate different characteristics of tubing to be severed by the cutter module.

18. The method of claim 17, wherein the cutter module assembly comprises at least two movable telescoping elements that comprises a first telescoping element that telescopes inside a stationary tubular body and a second telescoping element that telescopes inside the first telescoping element, the method further comprising:

configuring the spacers to establish different distances that the first telescoping element travels with respect to the second telescoping element.

19. The method of claim 17, wherein the first telescoping element comprises a shaft that extends to one of the shear blades, the method further comprising:

configuring each of the spacers to be fitted around the shaft.

20. An apparatus comprising:

a cutter module comprising opposable shear blades to sever a tubing in a well; and

differently-sized spacers adapted to be selectively installed in the cutter module to establish different offsets between the shear blades to accommodate different characteristics of the tubing.

21. The apparatus of claim 20, wherein

the cutter module comprises at least two movable telescoping elements that comprises a first telescoping element that telescopes inside a stationary tubular body and a second telescoping element that telescopes inside the first telescoping element, and

spacers are adapted to establish different distances that the first telescoping element travels with respect to the second telescoping element.

22. The apparatus of claim 20, wherein

the first telescoping element comprises a shaft that extends to one of the shear blades, and

each of the spacers is adapted to be fitted around the shaft.