Patent Application
20130000920
This disclosure relates in general to subsea wellhead seals, particular to a hybrid seal that has a metal-to-metal primary sealing portion and a secondary portion that serves as an emergency seal.
During creation of a subsea well, a wellhead assembly including a wellhead housing is located at the upper end of the wellbore at the sea floor. As the well is drilled deeper, a drill string passes through the wellhead housing. One or more casing strings are lowered through the wellhead housing, each supported with a casing hanger that lands in the bore of the wellhead housing. A packoff or casing hanger seal is set in a seal pocket between a side surface of the casing hanger and a sidewall of the bore. The casing hanger seal is preferably a metal-to-metal seal, which bests seals if the sealing surfaces on the casing hanger and on the sidewall of the bore are in good condition.
Wellhead drilling operations may cause damage to the sidewall of the wellhead housing bore before the casing hanger seal is installed. In particular, casing hangers and the high pressure wellhead housing can be damaged with scratches and gouges that range from minor scratches, such as a few thousandths deep, to major scratches, as much 0.1″ deep. To seal a casing hanger annulus that has been damaged, it may be necessary that the seal is constructed of a compliant material that can extrude and fill the scratches and gouges. If the desired metal-to-metal seal is unable to seal adequately, it is normally removed and replaced with an emergency seal. Normally, emergency seals consisting of elastomeric seal elements are used to seal the casing hanger annulus. The emergency seal may also have metal sealing elements combined with the elastomeric element.
Retrieving a primary metal-to-metal seal that fails to meet a pressure test is a time-consuming task. The operator has to release the primary seal from its set condition and retrieve it with a string of drill pipe. The operator then has to run an emergency seal with a running tool on a string of drill pipe. In deep water, the cost to trip a string of drill pipe from the drilling vessel to the subsea wellhead housing is expensive.
The seal assembly disclosed herein is designed to seal between inner and outer tubular members of a subsea wellhead assembly. The seal assembly includes a primary seal ring and a secondary seal ring. The primary and secondary seal rings are energized from a run-in to a set position by applying an energizing force. The energizing force required to move the secondary seal ring to the set position is less than the energizing force required to move the primary seal ring to the set position. After the seal assembly has landed between the inner and outer members, an energizing force applied to the primary seal ring transfers to the secondary seal ring to cause the secondary seal ring to move to the set position before the primary seal ring moves to the set position.
In the preferred embodiment, the primary seal ring has inner and outer annular legs that are separated from each other by an annular slot. An energizing ring with greater thickness than the slot is carried in a run-in position with its end engaging an entrance end of the slot. An energizing force supplied to the energizing ring, after the secondary seal ring has landed, initially transfers through the primary seal ring to the secondary seal ring, causing the secondary seal ring to move to the set position. A continuing force applied to the energizing ring after the secondary seal ring is in the set position pushes the energizing ring into the slot to move the primary seal ring to the set position.
Annular channels may be located on the inner side surface of the primary seal ring. An inlay of a metal softer than the metal of the primary seal ring is located within the channels. The primary seal ring has an annular force transferring leg that extends downward below these channels. The force transferring leg has a lower end that transfers setting force to the secondary seal ring.
The secondary seal ring preferably has a lower portion that provides sealing engagement with the inner and outer tubular members when the secondary seal ring is moved to the set position. An annular neck protrudes upwards from the lower portion alongside a side surface of the force transferring leg. A coupling device between the side surface of the force transferring leg and a side surface of the neck secures the secondary seal ring to the primary seal ring. The downward force supplied to the primary seal ring preferably does not pass through the coupling device.
Referring to
In this example, wellhead housing 11 has a set of wickers 23 located on bore sidewall 13. Additionally, casing hanger 15 may have a set of wickers 25 spaced directly across from wickers 23 on cylindrical portion 17c. Wickers 23 and 25 comprise small circumferential grooves extending around their respective surfaces. Normally, wickers 23 and 25 will have a saw tooth shape when viewed in cross section.
A seal assembly 27 is shown in a run-in position being lowered into seal pocket 19 prior to being set. Seal assembly 27 has an upper seal ring 29 and a lower seal ring 31. Upper seal ring 29 is a primary seal ring, and lower seal ring 31 is an auxiliary seal ring in this embodiment. Upper seal ring 29 has an upper portion 33 that sealingly engages wickers 23 and 25 when in the set position. Upper portion 33 has an inner leg 35 and an outer leg 37, both being annular, cylindrical members separated from each other by an annular slot 39. In this example, several annular channels 41 are formed on the outer diameter of outer leg 37. Channels 41 are axially separated from each other and are in planes perpendicular to the axis of bore sidewall 13. An inlay 43 of a soft metal alloy is located within each of the channels 41. In the preferred embodiment, inlay 43 comprises an alloy of tin and indium. When in the set position, inlay 43 will imbed into wickers 23 to enhance sealing. The material of inlay 43 is softer than the material of seal ring 29, which is typically formed of a steel alloy.
An energizing ring 45 serves to move upper seal ring 29 to the set position. Energizing ring 45 is engaged by a running tool (not shown) to lower seal assembly 27 into seal pocket 19 after casing hanger 15 has been cemented. The running tool also will apply a downward force to energizing ring 45 and upper seal ring 29 to energize lower seal ring 31. Continuing the downward force at a higher level will then energize upper seal ring 29. Energizing ring 45 has a radial thickness that is greater than the radial dimension of slot 39. In the run-in position, the lower end of energizing ring 45 is located at the upper end or entrance of slot 39 in abutment with upper ends of both legs 35, 37. When setting lower seal ring 31, energizing ring 45 remains in engagement with the upper ends of legs 35, 37. When setting upper seal ring 29, energizing ring 45 will extend into slot 39 a considerable distance, forcing inner leg 35 inward and outer leg 37 outward. The radial deformation of inner leg 35 and outer leg 37 exceeds the yield strength of the material of upper seal ring 29. Energizing ring 45 is secured to seal assembly 27 by a retainer ring 47 that has mating threads that engage threads on an upper extension 49 of outer leg 37.
Upper seal ring 29 has a force transfer leg 51 that extends downward from upper portion 33. Forced transfer leg 51 extends below the junction of inner leg 35 with outer leg 37 and in this example is aligned with outer leg 37. The outer diameter of force transfer leg 51 is approximately the same as the outer diameter of outer leg 37. The inner diameter of force transfer leg 51 is approximately the same as the inner diameter of outer leg 37. The thickness of force transfer leg 51 is thus considerably smaller than the radial dimension of seal upper portion 33 measured from the inner diameter of inner leg 35 to the outer diameter of outer leg 37. The difference in radial thickness results in a downward facing shoulder 53 at the lower end of upper portion 33 of upper seal ring 29. Force transfer leg 51 serves to set lower seal ring 31.
Lower seal ring 31 has a lower portion 55 that is at least partially elastomeric/thermoplastic and is deformed radially inward and outward to seal between casing hanger 15 and wellhead housing 11. Lower portion 55, better shown in
Referring to
A neck 81 extends upward from the upper end of inner spring member 79. In this example, neck 81 is a cylindrical ring that is formed separate from inner spring member 79. Neck 81 has an upper end that is in substantial abutment with downward facing shoulder 53. Neck 81 extends alongside and within the inner diameter of force transfer leg 51. The outer diameter of neck 81 is less than the inner diameter of force transfer leg 51, creating a cylindrical gap 83. Vertical dividing wall 59 extends upward within gap 83.
A coupling device, which is in this example comprises a threaded fastener 85, extends through a circular hole in neck 81 outward into a threaded receptacle in the inner diameter of force transfer leg 51. Fastener 85 extends through gap 83 and also through an elongated aperture 87 in vertical dividing wall 59. Fastener 85 thus secures lower seal ring 31 to force transfer leg 51. Neck 81 and force transfer leg 51 will be able to move downward relative to vertical wall 59 because of elongated aperture 87. The downward force passing through force transfer leg 51 and neck 81 does not pass through fastener 85 because neck 81 and force transfer leg 51 move downward in unison. The radial width of seal assembly 27 measured from an inner diameter of neck 81 to an outer diameter of force transfer leg 51 is no greater than a run-in radial width of upper seal ring 29. The radial width from the inner diameter of neck 81 to the outer diameter of force transfer leg 51, measured at the upper end of neck 81, is greater in this example than the radial width of the lower portion 55 of lower seal ring 31.
In operation, after casing hanger 15 has been installed within wellhead housing 11 and the casing cemented in place, the operator will install seal assembly 27. The operator actuates the casing hanger running tool (not shown) to lower seal assembly 27 into seal pocket 19. Nose 57 will land on shoulder 21. The running tool applies a downward force to energizing ring 45, which transfers the force to inner and outer legs 35, 37 of upper seal ring 29. The force to move inner and outer legs 35, 37 to the set position is considerably greater than the force required to move lower seal ring 31 to the set position. Consequently, this force applied by energizing ring 45 will initially pass through neck 81 and force transfer leg 51 through spring members 79, 77 to lower seal ring 31. Once the downward force is at a level sufficient to cause radial deformation of sealing ring sets 61, 63, upper end rings 73 will begin moving downward relative to nose 57 and vertical dividing wall 59. This downward movement causes metal rings 65 and elastomeric/thermoplastic rings 67 to deflect and move toward a flatter position. Edges of the metal rings and elastomeric/thermoplastic rings 65, 67 will sealingly engage casing hanger wall 17b and wellhead housing bore wall 13. Sealing engagement is also formed by the edges of rings 65, 67 on the inner and outer diameters of vertical dividing wall 59. Spring members 77 and 79 will contract in length and maintain a bias force against lower seal ring 31.
Once lower seal ring 31 is in the set position, the force required by the running tool will, increase. Continued application of the downward force at a greater level will move energizing ring 45 into slot 39. This results in inner leg 35 deflecting inward and outer leg 37 expanding outward, sealing against wickers 25 and 23. Wickers 23 and 25 do not extend significantly upward or downward from upper seal ring 29. In the preferred embodiment, lower seal ring 31 seals against smooth bore portions of casing hanger wall 17b and bore wall 13. The engagement of upper seal ring 29 with wickers 23, 25 also serves as a lock down to maintain lower seal ring 31 in the set position. Neck 81, spring members 77, 79 and a lower portion of force transfer leg 51 are located adjacent casing hanger conical portion 17a.
When pressure tested, lower seal ring 31 assists in preventing leakage past upper seal ring 29. If upper seal ring 29 forms a good metal-to-metal seal, lower seal ring 31 will have no function. However, if upper seal ring 29 fails to seat properly due to damage to the sealing surfaces, the emergency seal provided by lower seal ring 31 will assist in allowing a good pressure test to occur. It should not be necessary to retrieve seal assembly 27 and return with an emergency seal.
Various other types of auxiliary seal rings can be utilized. For example, rather than inner and outer sets of seal rings separated by vertical dividing wall, a single set of V-shaped metal and elastomeric/thermoplastic rings could be employed. Also, an entirely different type of lower seal may be employed as shown in
Lower seal ring 91 has an upper ring 99 of metal and a nose ring 101 also of metal. A flexible annular band 103 extends between upper ring 99 and nose ring 101, securing nose ring 101 to upper ring 99. Flexible band 103 is embedded within a central portion of an elastomer band 105 and is capable of changes in axial distance between upper ring 99 and nose ring 101. Elastomeric band 105 has a rim-in radial thickness that is initially greater than the radial thickness of seal pocket 27 as indicated by the dotted lines. When pushed into pocket 27, elastomeric band 105 will deform. A downward force of upper ring 99 against elastomeric band 105 after nose 101 has landed on shoulder 21 will push upper ring 99 toward nose ring 101 to cause elastomeric band 105 to seal between casing hanger surface 17b and bore wall 13. Preferably, upper ring 99 and nose ring 101 have metal lips 107 that face toward each other. An outer one of the metal lips 107 will seal and engage the inner wall of wellhead housing 11. An inner one of each of the metal lips 107 will seal and engage casing hanger outer sidewall 17b. As in the first embodiment, lower seal ring 91 is spaced below wickers 23, 25.
A neck 109 protrudes upward from upper ring 99 alongside and within the inner diameter of force transfer leg 97. A coupling device to secure neck 109 to force transfer leg 97 comprises threads 110 in this example. A downward facing shoulder 111 abuts an upper end of neck 109. The lower end of force transfer leg 97 abuts an upward facing shoulder 113, which is located outward of neck 109. The radial width from an inner diameter of neck 109 to an outer diameter of force transfer leg 99 is no greater than a run-in radial width of upper seal ring 89 or lower seal ring 91.
As in the first embodiment, the force required to set lower seal ring 91 is less than the force required to set upper seal ring 89. Consequently, the downward force of the running tool applied to energizing ring 96 will cause lower seal ring 91 to set first. Continued application of a downward force, but at a greater level, will then force inner and outer legs 93, 95 apart to set upper seal ring 89. Preferably, the downward force of energizing ring 96 does not pass through threads 110, rather passes directly to lower seal ring 91 because of the abutment of downward facing shoulder 111 with neck 109 and the abutment of force transfer leg 97 with shoulder 113.
While this disclosure has been shown only two of its forms, it should be apparent to those skilled in the art that it is not so limited but it susceptible to various changes without departing from the scope of disclosure.
