Patent Application
20110266006
Not applicable.
Not applicable.
1. Field of the Invention
The inventions disclosed and taught herein relate generally to connectors for connecting components of a well; and more specifically relate to connecting a blowout preventer to a surface well casing head at the surface.
2. Description of the Related Art
U.S. Pat. No. 4,188,050 discloses a “remotely controllable connector for releasably interconnecting the ends of two oil well flowlines. The connector comprises two coupling members, one of which is extended into engagement with the other by actuation of fluid cylinders, and ball joints in one or both coupling members to accommodate misalignment of the flowlines. A pair of mating cones mounted on the opposed ends of the two coupling members align the members into proper position during the connecting operation, and clamp means that are activated by remote control secure the two coupling members together in a fluid-tight connection. Seals are then set by remote control to seal all joints and to lock the coupling members in working alignment.”
U.S. Pat. No. 4,350,371 discloses a “pipe connector especially adapted for connecting subsea pipes includes a dart-shaped assembly that can be installed and sealed in a cylindrical housing to establish a fluid-tight connection between the assembly and the housing using a minimum of diver assistance. The connector housing includes an axial passage to receive the assembly, and an annular groove in the inner wall of the axial passage. The assembly includes a bore extending axially from one end thereof through a portion of the assembly, and a port extending radially from the axial bore through the wall of the assembly to the groove of the housing when the assembly is positioned in the housing. Another passage extends radially from the groove to the outside of the housing. A pair of annular resilient packing rings mounted between the assembly and the housing provide fluid-tight seals for fluid flow from the axial bore of the assembly through the radial port and the annular groove out through the radial passage in the housing. Means are provided for selectively locking and unlocking the assembly in the housing and for setting and releasing the resilient packing rings.”
U.S. Pat. No. 4,519,633 discloses a “pipe connector especially useful in tying back to a subsea wellhead with a marine riser. The connector comprises a body or sub, a collar surrounding the sub and carrying anti-rotation keys and a lock ring, and an actuator nut surrounding and threaded to the sub. The anti-rotation keys prevent rotation of the collar and the nut with respect to the receptacle into which the connector is run, and rotation of the sub with respect to the collar and nut locks the connector into the receptacle and establishes a metal-to-metal seal therewith.”
U.S. Pat. No. 4,606,557 discloses a “pipe connector especially suitable for interconnecting a marine riser to a subsea wellhead, the connector comprising an annular body that telescopes over the wellhead, and a plurality of lockdown screw assemblies extending through radial ports in the body to releasably grip and secure the connector to the wellhead. Each screw assembly comprises a lockdown dog for engaging the recess beneath the wellhead hub flange, a bolt-like dog retainer secured to the dog and slidably extending into a lockdown screw that is threaded into one of the radial ports, and a spring system for biasing the dog away from the lockdown screw towards engagement with the wellhead.”
U.S. Pat. No. 4,838,623 discloses a “end connector for double-pin track shoes or the like receives a pair of pins having arcuate grooves therein. The connector includes pin receiving openings having small diameter pin engaging arcuate surfaces, and large diameter arcuate grooves therebetween which nest arcuate portions of a spring therein. The spring also includes resiliently stressed portions that snap into the arcuate grooves in the pins when assembled, and a cap screw operatively connected between two walls of the connector clamps the connector onto the pins, thus providing double protection for maintaining the connector on the pins.”
U.S. Pat. No. 4,867,483 discloses a “pipe connector device for interconnecting first and second pipe elements using a retention member removably secured to the first pipe element by load elements. The retention member is secured to the second pipe element by pipe threads or a second retention member can be secured to the second pipe element by load elements and the first and second retention members threaded together. A seal is extended along a portion of the length of the first and second pipe elements adjacent to an end portion of each of the pipe elements to prevent leakage. This provides a fluid-tight seal which is relatively independent of any pressure exerted between the first and second pipe elements by the retention member.”
U.S. Pat. No. 4,927,192 discloses a “pipe connector load element interconnects a pipe element and a connector retention member. The load element is mounted in an annular groove on the outer circumference of the pipe element and in a groove adjacent to an internal bore in the retention member to secure the retention member to the pipe element. The load element includes a plurality of elongated components each having a slot extending lengthwise, and a flexible ribbon for threading through the slots. A pair of retention members are interconnected to connect a pair of pipe elements in an end-to-end arrangement.”
U.S. Pat. No. 5,131,692 discloses a “pipe connector device for selectively interconnecting a pair of pipe elements in an end-to-end relationship and for sealing a junction between the elements to prevent leaks. A first and a second pipe element each includes a cavity adjacent to a center bore in the pipe element. The first pipe element has a substantially smooth inner surface which defines an outer boundary of a first cavity. An annular seal mounted in the cavities seal the junction between the pipe elements. A threaded outer portion of the seal has a plurality of radially outer points which press against the inner surface of the first cavity to retain the annular seal in the first cavity when the pipe elements are separated.”
U.S. Pat. No. 5,259,459 discloses a “subsea wellhead tieback connector actuated solely by axial motion to achieve connection to and disconnection from the wellhead. The connector includes interconnected inner and outer bodies, a split lock ring surrounding the inner body, and an energizing mandrel for non-rotary axial movement to expand the lock ring into engagement with a wellhead component.”
U.S. Pat. No. 5,775,427 discloses a “subsea wellhead tieback connector operatively used to connect to a marine riser pipe or a well conductor in a manner that that will not unthread or unloosen the joints of the riser pipe being unlocked. The tieback connector operates with a novel internal latching mechanism having a hydraulic piston, an inner body that stretches and deflects in a unique manner resulting in compression spring forces at two locations, an expanding lock ring, a threaded adjustment ring, and a reaction ring. During operation the tieback connector creates an enhanced mechanical advantage to originate a required pre-load force without the necessity of having to generate a large hydraulic force that would otherwise be needed.”
U.S. Pat. No. 6,481,504 discloses a “flowline connector having a first connector portion for mounting on a first piece of subsea equipment, such as a wellhead. A second connector portion of the flowline connector is attached to an end portion of a flowline. Each connector portion has a respective guide interengageable by lowering the second connector portion, on the end portion of the flowline, into the first connector portion. The guides allow the second connector portion to pivot relative to the first connector portion to bring the first connector portion and the second connector portion into axial alignment for make-up of a fluid tight connection therebetween. The second connector portion has a subsea equipment package, for example chokes, gas/water separators, gas liquifiers, pumps and the like, for connection to the first piece of the subsea equipment.”
U.S. Pat. No. 6,666,272 discloses an “externally actuatable tieback connector for establishing fluid communication and force resisting connection of a conduit to a subsea wellhead having an internal locking geometry. The tieback connector has a body structure that is adapted for landing on a wellhead, with a part thereof extending into the wellhead and carrying a split lock ring. A lock energizing element, moveable relative to the body structure, has a locking position expanding the lock ring into locking and pre-load force transmitting engagement with the internal locking geometry of the wellhead and an unlocking position releasing the tieback connector from the wellhead. One or more drive members extend from the lock energizing element and are exposed externally of the connector body and wellhead for engagement and actuating movement by a lock actuating tool such as a ROV or the like.”
The inventions disclosed and taught herein are directed to [an improved system for connecting a blowout preventer to a surface well casing head at the surface.
The present invention comprises a connector to secure a blow out preventer to tubing or casing head of a well or wellhead. The connector may include an adapter configured to be secured to the blow out preventer. The connector may be configured to secure the adapter to the tubing and provide, within fifteen minutes, a seal operable to withstand ten thousand pounds per square inch of pressure. The connector may include both a hydraulically operated locking segment and a separate mechanical locking segment, and wherein both locking segments may be transitioned from a fully retracted position to a fully locked position within fifteen minutes. The blow out preventer, the tubing, and the connector may be located, and the locking segments may be operated, above sea level. The mechanical locking segment may manually, semi-, or fully-automatically retain the hydraulically operated locking segment in the fully locked position. The hydraulically operated locking segment may be configured to remain in the fully locked position once hydraulic pressure is decreased. The seal may be a metal to metal seal. The seal may include two metal ring gaskets, at least one of which is configured to fit in an American Petroleum Institute R-54 ring groove in a top surface of the tubing. The connector may be configured to accommodate up to ten degrees of misalignment between the blow out preventer and the tubing. The connector may include a load ring configured to be threaded, welded, integral to, or otherwise secured onto the tubing. The load ring may provide a shoulder at a distal end of the tubing, and the hydraulically operated locking segment may engage the shoulder to provide the seal. The hydraulically operated locking segment may include a tubular piston that moves longitudinally between the fully retracted position and the fully locked position and a plurality of wedges positioned around the piston, such that longitudinal movement of the piston drives the wedges radially inward to engage the shoulder, thereby providing the seal.
The present invention also comprises a method of securing a blow out preventer to tubing or casing head of a well or wellhead. The method may comprise lowering a connector connected to the blow out preventer onto the tubing, pressurizing a hydraulically operated locking segment of the connector, thereby causing the hydraulically operated locking segment to move from a fully retracted position to a fully locked position, and thereby providing a seal between the blow out preventer and the tubing, and retaining the hydraulically operated locking segment in the fully locked position utilizing a separate mechanical locking segment. The entire process may be completed within fifteen minutes. The entire process may be performed above sea level. The seal may be a metal to metal seal capable of withstanding ten thousand pounds per square inch of pressure.
The Figures described above and the written description of specific structures and functions below are not presented to limit the scope of what Applicants have invented or the scope of the appended claims. Rather, the Figures and written description are provided to teach any person skilled in the art to make and use the inventions for which patent protection is sought. Those skilled in the art will appreciate that not all features of a commercial embodiment of the inventions are described or shown for the sake of clarity and understanding. Persons of skill in this art will also appreciate that the development of an actual commercial embodiment incorporating aspects of the present inventions will require numerous implementation-specific decisions to achieve the developer's ultimate goal for the commercial embodiment. Such implementation-specific decisions may include, and likely are not limited to, compliance with system-related, business-related, government-related and other constraints, which may vary by specific implementation, location and from time to time. While a developer's efforts might be complex and time-consuming in an absolute sense, such efforts would be, nevertheless, a routine undertaking for those of skill in this art having benefit of this disclosure. It must be understood that the inventions disclosed and taught herein are susceptible to numerous and various modifications and alternative forms. Lastly, the use of a singular term, such as, but not limited to, “a,” is not intended as limiting of the number of items. Also, the use of relational terms, such as, but not limited to, “top,” “bottom,” “left,” “right,” “upper,” “lower,” “down,” “up,” “side,” and the like are used in the written description for clarity in specific reference to the Figures and are not intended to limit the scope of the invention or the appended claims.
Applicants have created a connector to secure a blow out preventer to tubing or a casing head of a well or wellhead and a method of securing a blow out preventer to tubing or a casing head of a well or wellhead utilizing the connector. The connector may include an adapter configured to be secured to the blow out preventer. The connector may be configured to secure the adapter to the tubing and provide, within fifteen minutes, a seal operable to withstand ten thousand pounds per square inch of pressure. The connector may include both a hydraulically operated locking segment and a separate mechanical locking segment, and wherein both locking segments may be transitioned from a fully retracted position to a fully locked position within fifteen minutes. The blow out preventer, the tubing, and the connector may be located, and the locking segments may be operated, above sea level. The mechanical locking segment may manually, semi-, or fully-automatically retain the hydraulically operated locking segment in the fully locked position. The hydraulically operated locking segment may be configured to remain in the fully locked position once hydraulic pressure is decreased. The seal may be a metal to metal seal. The seal may include two metal ring gaskets, at least one of which is configured to fit in an American Petroleum Institute R-54 ring groove in a top surface of the tubing. The connector may be configured to accommodate up to ten degrees of misalignment between the blow out preventer and the tubing. The connector may include a load ring configured to be threaded, welded, integral to, or otherwise secured onto the tubing. The load ring may providing a shoulder at a distal end of the tubing, and the hydraulically operated locking segment may engage the shoulder to provide the seal. The hydraulically operated locking segment may include a tubular piston that moves longitudinally between the fully retracted position and the fully locked position and a plurality of wedges positioned around the piston, such that longitudinal movement of the piston drives the wedges radially inward to engage the shoulder, thereby providing the seal.
As mentioned above, the connector 10 may include the adapter 12 that mates to the BOP 14. The adapter 12 may be generally tubular and include an upper flange 20 and/or one or more upper ring grooves 22 to receive a ring gasket 24 therein, to seal the adapter 12 to the BOP 14. The adapter 12 also preferably includes a planar adapter mating surface 26 and/or one or more mating ring grooves 28 to receive a mating gasket 30 therein, to seal the adapter 12 to the tubing, or casing head, of the well 14. The mating ring grooves 28 may conform to the American Petroleum Institute R-54 standard. The mating gasket 30 may at least partially fit within the mating ring groove 28 and may be partially crushed by operation of the connector 10 to provide a seal between the adapter 12 and the well 16 operable to withstand ten thousand pounds per square inch of pressure. The mating gasket 30 may be constructed of metal to provide a metal to metal seal between the adapter 12 and the well 16. More specifically, the mating gasket 30 preferably forms the seal by being crushed against a well gasket 32 partially recessed within a well ring groove 34 of a planar well mating surface 36.
Referring also the
Referring also to
More specifically, as pressurized hydraulic fluid is injected into a locking port 48 of the outer housing 38, thereby pressurizing the hydraulically operated locking segment 40, that pressure is applied to a locking surface 50 of the piston 44. In one embodiment, the locking surface 50 is an upper annular surface. This hydraulic pressure pushes against the locking surface 50, driving the piston 44 from the fully retracted position, as shown in
In any case, as the piston 44 is driven from the fully retracted position toward the fully locked position, an inner sloping surface 56 of the piston 44 slidably engages an outer sloping surface 58 of the wedges 46, thereby driving the wedges 46 radially inward. As the wedges 46 are driven radially inward, inner angled surfaces 60 of the wedges 46 slidably engage an outer angled surface 62 forming a shoulder 64 of the well 14, or tubing or casing head of the well 14. When the piston 44 has reached the fully locked position, the inner sloping surface 56 of the piston 44 may have moved past the outer sloping surface 58 of the wedges 46, such that a longitudinally flat inner surface 66 of the piston then engages longitudinally flat outer surfaces 68 of the wedges 46.
More specifically, the longitudinally flat inner surface 66 and the longitudinally flat outer surfaces 68 are preferably generally flat, when compared to the inner sloping surface 56 and the outer sloping surface 58, respectfully. However, as previously mentioned, the piston 44 may be tubular, and therefore the longitudinally flat inner surface 66 and the longitudinally flat outer surfaces 68 might only be flat longitudinally, such as along a Y axis, but be curved with respect to other axis, such as along an X-Z plane. In any case, because the piston 44 is configured to move longitudinally, and in the fully locked position, the piston 44 may engage the wedges 46 with longitudinally flat surfaces 66,68, outward force exerted on the wedges 46 will not tend to move the piston 44, thereby allowing the hydraulically operated locking segment 40 to remain in the fully locked position even with a reduction or complete loss of hydraulic pressure.
Of course, the pressurized hydraulic fluid may still be injected into the unlocking port 52 to drive the piston 44 away from the fully locked position, if desired. However, because of the pressures involved, the wedges 46 may tend to stay fully engaged with the shoulder 64. This may be the case where the angles of the inner angled surfaces 60 of the wedges 46 and the outer angled surface 62 of the shoulder 64 are especially shallow. Therefore, the hydraulically operated locking segment 40 may also include a manually or hydraulically operated release 70. In one embodiment, the release 70 includes a retracting bolt 72 secured to each wedge 46 and a retracting nut 74 surrounding each retracting bolt 72. The retracting nut 74 may be threaded into the outer housing 38, such that unscrewing the retracting nut 74 pulls on a head of the retracting bolt 72, thereby pulling the wedge 46 radially outward.
The shoulder 64 may be integral to a distal end of the well 14. Alternatively, the shoulder 64 may be formed onto a load ring 75 that may be threaded, welded, or otherwise secured to the distal end of the well 14, or tubing or casing head of the well 14.
The mechanical locking segment 42 may include one or more retaining pins 76 and retaining nuts 78. The retaining pins 76 may be configured to slide into one or more recesses 80 in the piston 44, when the piston 44 is in the fully locked position. The retaining pins 76 may be slidably retained in one or more pockets 82 of the outer housing 38 and held in place, and/or forced against the piston 44, by the retaining nuts 78.
In certain applications, the mechanical locking segment 42 may be configured to operate automatically. For example, the mechanical locking segment 42 may include one or more resilient members 84, such as a spring, between the retaining pins 76 and the retaining nuts 78. This resilient members 84 may allow the retaining pins 76 to slide radially outwardly and into the pocket 82 of the outer housing 38 when the piston 44 begins to pass by until the recess 80 in the piston 44 is aligned with the retaining pins 76, in which case the resilient member 84 pushes the retaining pins 76 radially inward to engage the recess 80 in the piston 44, thereby locking both the hydraulically operated locking segment 40 and the mechanical locking segment 42 in the fully locked position.
The connector 10 may also be configured to accommodate up to ten degrees of misalignment between the BOP 14 and the wellhead 16. For example, the BOP 14 center of gravity is not always perfectly in the vertical plane. In some cases, the BOP 14 may be at an angle of up to ten degrees from vertical. With the wellhead 16 preferably being vertical, the BOP 14 and the wellhead 16 may be misaligned by up to ten degrees.
To aid in accommodating this, in one embodiment, the connector 10 includes a guide funnel 85 to guide a lower end of the connector 10 onto the wellhead 16. The guide funnel 85 may include a lower sloped surface 86 which engages an upper sloped surface 88 of the load ring 75, or shoulder 64. As the connector 10, connected to the BOP 14, is lowered onto the wellhead 16, the lower sloped surface 86 engages the upper sloped surface 88, thereby guiding the connector 10 onto and around the wellhead 16. When the load ring 75, the shoulder 64, or the wellhead 16 meets the adapter 12, then connector 10 begins to align the adapter 12, the BOP 14, and the wellhead 16. Once the connector 10 and the BOP 14 are resting atop the wellhead 16, the BOP 14 will be aligned with the wellhead 16.
Thus, the connector 10 of the present invention may greatly speed up the time it would otherwise take to connect the BOP 14 to the wellhead 16. More specifically, it should take no longer than fifteen minutes from the time the load ring 75 is secured to the well 16 until both the hydraulically operated locking segment 40 and the mechanical locking segment 42 are in the fully locked position. In some cases, it may take no longer than fifteen minutes from the time the connector 10 beings to be lowered onto the wellhead 16 until both the hydraulically operated locking segment 40 and the mechanical locking segment 42 are in the fully locked position, thereby providing the seal, such as a metal to metal seal capable of withstanding ten thousand pounds per square inch of pressure. In some cases, it may take no longer than fifteen minutes to secure the shoulder 64 to the wellhead and complete the connection between the BOP 14 and the wellhead 16. With a trained and experienced crew, any or all these times may be reduced to twelve minutes, or even ten minutes.
Hydraulic connectors may be used to secure production risers, pipelines, and subsea wellheads. On the surface, or above sea level, mechanical connectors are typically used, such as locking pins or segmented clamps. Using typical mechanical methods may extend beyond the required time span, such as the fifteen minutes mentioned above. So, the connector 10 of the present invention provides the hydraulically operated locking segment 40 and the mechanical locking segment 42, which may be manually operated, semi- or fully-automatic, to expedite the connection between the BOP 14 and the wellhead 16, with connector 10, the BOP 14, and the wellhead 16 all being on the surface, or above sea level.
As the connector is slowly lowered, the guide funnel properly orients the connector and BOP back to the true vertical position. The connector may include an outer housing, piston, guide funnel, lock segments, threaded load ring, BOP adapter, retaining nut and pin, and retracting nuts and bolts. The outer housing allows internal pressure to be applied to the piston to lock and unlock the connector.
To lock the connector, hydraulic pressure is applied to the lock, or locking, port. The piston will travel downward (vertically) engaging several wedges that are otherwise loosely resting in a static position. As the piston continues to travel downward (vertically), the wedges travel inward (radially) reacting against the taper, or inner sloping surface, of the piston. The wedges then begin to react with the load ring that is installed onto the casing head, which generates a crushing/squeezing force in order to get a metal-to-metal seal.
This crushing/squeezing force may be required for the metal-to-metal seal engagement to be rated to ten thousand pounds per square inch of pressure, or more. The metal-to-metal seal may be provided by a custom ring gasket fitted in an API R-54 ring groove. The R-54 ring groove also allows the connector to makeup to a five thousand pounds per square inch tubing head assembly.
Once the piston is fully stroked into the locked position, the piston and wedges form a flat to flat bearing surface. This flat to flat will not allow the connector to unlock once the hydraulic pressure is bled off from the system, by translating any axial/tension load to a radial/hoop load.
As a secondary safety measure to ensure the piston does not travel upward and unlock, a spring loaded or mechanical retaining pin and retaining nut may be utilized that engages in a groove, or recess, on the piston once the piston is at full stroke. The retaining pin and retaining nut may provide a set designed force that may ensure that if the piston does experience any axial/tension force, the retaining pin will not allow the piston to travel upward and unlock the connector during service.
To release/unlock the connector, pressure may be applied to the unlock port which may stroke the piston upward (vertically). This may allow the wedges to freely retract off the taper of the load ring, or the outer angled surface of the shoulder, that is on the casing head.
The connector may include a secondary means of retracting the locking segments in case they do not fully disengage. Each wedge may be coupled to a retracting bolt housed inside a retracting nut, which may be attached to the outer housing. To retract the wedges (individually), a wrench, a socket, an impact, etc. can be used to loosen the retracting nut which will react with a stop shoulder, or head, on the retracting bolt, resulting in pulling (retracting) the wedges outward and fully unlocking the connector.
The retracting bolts and wedges may thread together with a left-handed thread and the retracting nuts may thread to the outer housing 38 utilizing a right-handed thread, or vise versa. This opposite direction of threads may eliminate the opportunity of the retracting bolts and wedges to become unthreaded.
In this manner, the surface connector 10 of the present invention will not only speed up the operation of connecting the BOP 14 to the casing wellhead 16, but it may also decrease the safety risk of having personnel under the BOP 14 making up a bolted flange connection.
Other and further embodiments utilizing one or more aspects of the inventions described above can be devised without departing from the spirit of Applicant's invention. For example, other dimensions, angles, and/or materials might be used. Further, the various methods and embodiments of the present invention can be included in combination with each other to produce variations of the disclosed methods and embodiments. Discussion of singular elements can include plural elements and vice-versa.
The order of steps can occur in a variety of sequences unless otherwise specifically limited. The various steps described herein can be combined with other steps, interlineated with the stated steps, and/or split into multiple steps. Similarly, elements have been described functionally and can be embodied as separate components or can be combined into components having multiple functions.
The inventions have been described in the context of preferred and other embodiments and not every embodiment of the invention has been described. Obvious modifications and alterations to the described embodiments are available to those of ordinary skill in the art. The disclosed and undisclosed embodiments are not intended to limit or restrict the scope or applicability of the invention conceived of by the Applicants, but rather, in conformity with the patent laws, Applicants intend to fully protect all such modifications and improvements that come within the scope or range of equivalent of the following claims.
This application is a non-provisional application, and claims priority benefit, of U.S. Provisional Application 61/330,231, filed Apr. 30, 2010, which is incorporated herein by specific reference.
| Number | Date | Country | |
|---|---|---|---|
| 61330231 | Apr 2010 | US |
