US3521909A - Remote underwater wellhead connector - Google Patents

Remote underwater wellhead connector Download PDF

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Publication number
US3521909A
US3521909A US456968A US3521909DA US3521909A US 3521909 A US3521909 A US 3521909A US 456968 A US456968 A US 456968A US 3521909D A US3521909D A US 3521909DA US 3521909 A US3521909 A US 3521909A
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tubular
tubular body
wellhead
translatory
sleeve
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US456968A
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Cicero C Brown
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Richfield Oil Corp
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Richfield Oil Corp
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B33/035—Well heads; Setting-up thereof specially adapted for underwater installations
    • E21B33/038—Connectors used on well heads, e.g. for connecting blow-out preventer and riser

Definitions

  • This invention relates to an apparatus for use at offshore wells and pertains more particularly to latch means for securing a well tool, such as a blowout preventer, a riser pipe or a production mandrel, to a wellhead.
  • a well tool such as a blowout preventer, a riser pipe or a production mandrel
  • Another object of the invention is to provide mechanical latch means for (releasably) securing well tools to a wellhead.
  • Still another object is to provide a mechanical latch means which is controllable from a location remote therefrom for securing a well tool to a wellhead.
  • a still further object of this invention is to provide a mechanical latch means, which is remotely controlled, for releasably securing a well tool to a wellhead.
  • Another object of this invention is ot provide a mechanically actuated latch means for latching a well tool to an underwater wellhead whereby substantially all axial movement and lateral movement of said well tool may be prevented.
  • Still another object of this invention is to provide a mechanically actuated latch means having a mechanically actuated compression seal. It is also an object of this invention to provide a tool for latching a tubular body into an open ended tubular member which tool can be mechanically internally released.
  • FIG. 1 is an elevational view, partially in section, of the latch means in the position just after inserting the well tool to be latched into an underwater wellhead;
  • FIG. 2 is an elevational view, partially in section, show- 'ice ing the relationship of the latch parts after the latch has been set;
  • FIG. 3 is an elevational view, partially in section, similar to FIG. 2 showing the relationship of the latch parts after the latch has been released and retrieved a short distance;
  • FIG. 4 is a transverse sectional view taken on line 4-4 of FIG. 1;
  • FIG. 5 is a transverse sectional view taken on line 5-5 of FIG. 3.
  • a wellhead H which, it will be understood, is connected to the upper end of a large diameter pipe (not shown) extending into a well bore drilled into a formation underlying a body of water.
  • the wellhead H extends a short distance above the top of the land bottom, as shown in co-pending application of C. E. Wakefield, Jr., for Underwater Drilling Method, Ser. No. 454,019 filed May 7, 1965, now Pat No. 3,398,790, and is provided with an annular groove at 11 for attaching blowout preventers, riser pipe, etc. used while drilling below the conductor pipe.
  • the upper end of the wellhead may be provided with a downwardly and inwardly inclined surface 13 which serves as a guide for the tools to be inserted into the bore of the wellhead H.
  • the well body or mandrel 15 is supported in wellhead H when its beveled shoulder 60 is lowered into engagement with the inclined surface 13 of wellhead H.
  • a latch device is formed by providing an inner annular groove 12 in wellhead H into which well apparatus such as a production head, locks.
  • the inner annular groove 12 defines an upper and lower inclined end walls 12a and 12b, respectively, which serve as the locking or landing recess for the co-operating inner portions of the latch device.
  • the inner portion of the latch is the device to be latched into the wellhead and includes a tubular body 15 having an external diameter to form a close sliding fit in the bore of Wellhead H.
  • Body 15 may have an internally threaded box (not shown) at its upper end which serves to connect the tubular body 15 to a pipe string which is used to lower the tubular body 15 from a drilling structure at the surface of the body of water, into the wellhead.
  • Seal packing 16 of any suitable type is seated in annular grooves 17 formed on the exterior of the tubular body, and is adapted to form a fluid-tight seal between the latter and the wellhead when the tubular body is inserted into the wellhead.
  • a shoulder 20 is defined where the tubular body 15 outside diameter reduces to the tubular section 19.
  • An annular ring 21 is supported against shoulder 20 by springs 24. Threaded into the lower face 22 of this ring are a plurality of socket head cap screws 10 provided to retain an annular T-head dog retainer 23 in limited axial movement relative to the tubular section 19.
  • a plurality of holes 25 are drilled through the retainer 23 to accommodate the cap screws.
  • Counterbores 26 are provided in the lower face of the retainer large enough to provide clearance for the heads 27 of the cap screws and deep enough to provid for limited longitudinal travel of the cap screw heads within the counterbores.
  • Mounted about each of the cap screw shanks 10 and pressing against the lower face of annular ring 21 and the upper face of the T-head dog retainer 23 are a plurality of springs 24. These springs resiliently urge the dog retainer 23 away from the lower annular ring to its full extended position where they are retained from further extension by the heads of the cap screws in the counterbores of the dog retainer.
  • the reduced diameter tubular section 19 has an annular groove 28 in which is provided a snap ring stop 29 for the purpose of limiting the downward travel of the dog retainer 23, springs, cap screws and upper annular ring assembly.
  • T-head dogs 30 Mounted in a plurality of T-heads formed in the lower end of the dog retainer 23 is a plurality of T-head dogs 30.
  • the dogs are provided to latch the tubular body to the wellhead H.
  • the T-head connection between the retainer :and the dogs allow for a limited radial movement of the dogs.
  • a retainer cover ring 31 is provided over the T-head windows in the slip retainer to limit the radial outward movement of the T-heads of dogs 30.
  • a tapered head sleeve 32 Mounted about the tubular body and just below the dogs is a tapered head sleeve 32.
  • the upper end of the sleeve 32 has an external tapered portion 33 that mates with an internal taper on the lower end of the slips.
  • the tapered portion 33 causes the dogs to move radially outward.
  • the lower end of the sleeve 32 is counterbored to form an internal shoulder 34a.
  • a stop ring 36 is mounted in an external annular groove 35' on the tubular section 19. This stop ring serves to retain the cone on the tubular support allowing for a limited axial movement therewith.
  • a bearing support 37 is provided in the bottom surface of sleeve 32.
  • a translatory member 41 is connected to the tubular body as for example, by the male acme threads 18 on the lower end of the tubular section 19 engaging mating box acme threads provided in the upper end of the translatory member. These connecting threads are preferably left-hand.
  • a bearing support 39 is provided in the upper face of translatory member 41 adjacent support 37 of sleeve 32 and bearing rings 38 are provided in the supports 37 and 39. The connection between the translatory member 41 and the lower end of the tubular member 19 allows for relative axial movement between the two members which allows the sleeve 32 to set and unset the dogs as they are made up or unscrewed.
  • a seal 42 is provided in the counterbore of the translatory member to seal off between the translatory member 32 and the tubular member 19.
  • annular retainer is attached to the sleeve 32 with a suitable thread 44 and set screwed at 45.
  • the lower end of the retainer 40 has a female flange member 46 that slips over the reduced diameter of the translatory member and retains the latter because of a male flange member 47 on the upper end of the translatory member. Between these two flanges are provided anti-friction rings 43.
  • a further reduced section 49 may be provided to allow clearance inside the upper end of a casing or liner 50 which may be set within the well-head H.
  • Another reduction 51 which provides space to mount seal or packing 52 which seals off between the latch member 19 and the liner 50.
  • Packing ring 53 retains packing 52.
  • Packing ring 53 has an outside diameter which allows clearance inside the liner and an inside diameter that clears reduced diameter 51.. Its end extends a slight distance below the lower end of the translatory member 41, to allow for compression of seal 52.
  • the packing ring 53 is shear pinned to the translatory member and this pin 63 also shear pins the seal setting body 54 in the unset position.
  • the seal setting body 54 is attached to the translatory member by an acme left-hand thread 56 and the lower end of the seal setting body 'has a flange 55 that bears against the packing ring 53.
  • On the upper outside diameter of the seal setting body is provided a male thread at a reduced diameter from the thread 56 for attaching an internally threaded stop ring 58.
  • This stop ring limits the axial movement of the seal setting body.
  • the stop ring 58 is set screwed from the upper face of this ring to the seal setting body by set screw 59.
  • tubular body or mandrel 15 may be secured to the lower end of the drill string or a riser and lowered from the drilling structure for coupling to the wellhead H.
  • the tubular body 15 is thus introduced into the bore of housing or wellhead H.
  • the drill string and tubular body 15 may be guided into the wellhead H with conventional guide lines, or body 15 may be stripped over a drill pipe which may be left in the hole for this purpose.
  • body 15 may be stripped over a drill pipe which may be left in the hole for this purpose.
  • the tubular body 15 having coupling device therein is inserted in the bore of the wellhead H and lowered therein. As this occurs, the beveled upper inside diameter of the wellhead will guide the coupling device within its bore.
  • the dogs 30 which are forced outwardly due to the springs forcing the dogs against the sleeve 32 will be forced to retracted position as the dogs land against the beveled portion 13 of the wellhead H.
  • the dogs When the beveled shoulder 60 on the upper end of the coupling device seats on the mating bevel 13 of the wellhead, the dogs will be indexed longitudinally adjacent the annular groove 12 in the wellhead. As this occurs, the dogs will expand radially into this groove in latched relationship therewith as the springs expand the dogs against the tapered top of the sleeve 32.
  • the drill string may then be picked up to check the locked position and prove that it is anchored. At this point the seal 52 has not yet been set nor has the axial play that is left between the coupling members been removed.
  • a torsional gripping tool 57 is run adjacent the inner surface 62 of the seal setting member 54 and right-hand rotation is begun.
  • the torsional gripping means -57 will grip the inner surface 62 and cause the setting member or sleeve 54 to rotate.
  • This rotation causes the translatory member 41 to rotate also, as it is shear pinned to the seal setting member 62 by shear pin 63.
  • the translatory member 41 rotates to the right it will move upon threads 18 relative to the body 15, pushing the dogs 30 against the shoulder 12a in the housing. This position is shown in FIG. 2. As this occurs the rotation of the translatory member stops and shear pin 63 will be sheared from the seal ring 53 and the seal setting member 54.
  • the torsional gripping means 57 is rerun adjacent the surface 62 of the seal setting means and rotated to the left. This will cause the seal setting member 54 to move downward releasing the seal 52. As this occurs the lower face of the retainer nut 58 hits the left-hand acme thread and stops relative rotation between the seal setting member and' the translatory member. These members then rotate together causing the thread 18 to unscrew causing the translatory member to move downward. This causes the sleeve 32 to be pulled from under the dogs 30 until they reach the fully retracted position as shown in FIG. 3. The torsional tool 57 is now removed from the hole and the casing member may then be picked up, uncoupling the device so that it can be removed to the barge.
  • An apparatus for latching a tubular body into the open end of a tubular member having an internal shoulder therein and internally mechanically releasing said body from said tubular member comprising in combination:
  • An apparatus for latching a tubular body into the open end of a tubular member having an internal shoulder therein and internally mechanically releasing said body from said tubular member comprising in combination:
  • tapered means associated with said translatory member for holding said dog radially outward against said shoulder
  • said tapered shoulder means retaining said dog radially outwardly in said shoulder and against the top of said shoulders.
  • An apparatus for latching a tubular body into the open end of a tubular member having an internal shoulder therein and internally mechanically releasing said body from said tubular member comprising in combination:
  • tapered means associated with said translatory member for holding said dog radially outward against said shoulder
  • An apparatus for latching a tubular body into the open end of a tubular member and internally mechanically releasing said body from said tubular member comprising in combination:
  • said translatory member for rotating said translatory member relative to said tubular body to drive said holding means upwardly against said securing means to move said securing means radially outwardly against the internal surface of said tubular member
  • said holding means retaining said securing means radially outwardly against the internal surface of said tubular member.
  • the apparatus of claim 6 including in said combination, a sleeve engageable with said translatory member and wherein said moving means includes means for engaging said sleeve.
  • An apparatus for latching a tubular body into the open end of a tubular member and internally mechanically releasing said body from said tubular member comprising in combination:
  • tapered means movable by said translatory member for holding said securing means radially outward against the inner surface of said tubular member

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)

Description

July 28, 1970 c. c. BROWN 3,521,909
REMOTE UNDERWATER WELLHEAD CONNECTOR Filed May 19, 1965 2 Sheets-$heet l BY 7/z/ Z a: 4/
July 28, 1970 c. c. BROWN REMOTE UNDERWATER WELLHEAD CONNECTOR 2 Sheets--5heet Filed May 19, 1965 I E NTOR.
United States Patent US. Cl. 2853 9 Claims ABSTRACT OF THE DISCLOSURE This invention relates to a mechanism for connecting a well tool such as a blowout preventer or a riser pipe to a tubular member in which the tool is supported. The mechanism is mechanically latched, unlatched, and packed off with a device which is operable internally of the well tool by rotating a translatory member.
This invention relates to an apparatus for use at offshore wells and pertains more particularly to latch means for securing a well tool, such as a blowout preventer, a riser pipe or a production mandrel, to a wellhead.
In the search to find new oil fields, an increasing amount of drilling has been conducted at offshore locations. As the depths have increased, it has become neces ary to drill these wells from floating barges and locate the casing head and the wellhead equipment underwater to obviate the need for erecting a platform for placement of the wellhead equipment. In order to install equipment of this type underwater in depths greater than the shallow depth at which a diver can operate, it has become neces sary to look to remotely installed equipment. Concurrently on the market are designs of underwater latches that are hydraulically actuated through flexible hoses that may become broken. These broken hoses may be repaired by a diver in relatively shallow water; but at the greater depths this becomes increasingly diificult, if not impossible.
It is therefore one object of this invention to provide a new and improved latch means for securing well tools to a wellhead.
Another object of the invention is to provide mechanical latch means for (releasably) securing well tools to a wellhead.
Still another object is to provide a mechanical latch means which is controllable from a location remote therefrom for securing a well tool to a wellhead.
A still further object of this invention is to provide a mechanical latch means, which is remotely controlled, for releasably securing a well tool to a wellhead.
Another object of this invention is ot provide a mechanically actuated latch means for latching a well tool to an underwater wellhead whereby substantially all axial movement and lateral movement of said well tool may be prevented.
Still another object of this invention is to provide a mechanically actuated latch means having a mechanically actuated compression seal. It is also an object of this invention to provide a tool for latching a tubular body into an open ended tubular member which tool can be mechanically internally released.
Additional objects and advantages of the invention will become apparent from the following description on an embodiment of the present invention when taken in conjunction with the appended claims and the accompanying drawings, wherein: I
FIG. 1 is an elevational view, partially in section, of the latch means in the position just after inserting the well tool to be latched into an underwater wellhead;
FIG. 2 is an elevational view, partially in section, show- 'ice ing the relationship of the latch parts after the latch has been set;
'FIG. 3 is an elevational view, partially in section, similar to FIG. 2 showing the relationship of the latch parts after the latch has been released and retrieved a short distance;
FIG. 4 is a transverse sectional view taken on line 4-4 of FIG. 1;
FIG. 5 is a transverse sectional view taken on line 5-5 of FIG. 3.
Referring to the drawings, there is shown a wellhead H which, it will be understood, is connected to the upper end of a large diameter pipe (not shown) extending into a well bore drilled into a formation underlying a body of water. The wellhead H extends a short distance above the top of the land bottom, as shown in co-pending application of C. E. Wakefield, Jr., for Underwater Drilling Method, Ser. No. 454,019 filed May 7, 1965, now Pat No. 3,398,790, and is provided with an annular groove at 11 for attaching blowout preventers, riser pipe, etc. used while drilling below the conductor pipe. The upper end of the wellhead may be provided with a downwardly and inwardly inclined surface 13 which serves as a guide for the tools to be inserted into the bore of the wellhead H. The well body or mandrel 15 is supported in wellhead H when its beveled shoulder 60 is lowered into engagement with the inclined surface 13 of wellhead H.
A latch device is formed by providing an inner annular groove 12 in wellhead H into which well apparatus such as a production head, locks. The inner annular groove 12 defines an upper and lower inclined end walls 12a and 12b, respectively, which serve as the locking or landing recess for the co-operating inner portions of the latch device. The inner portion of the latch is the device to be latched into the wellhead and includes a tubular body 15 having an external diameter to form a close sliding fit in the bore of Wellhead H. Body 15 may have an internally threaded box (not shown) at its upper end which serves to connect the tubular body 15 to a pipe string which is used to lower the tubular body 15 from a drilling structure at the surface of the body of water, into the wellhead.
Seal packing 16 of any suitable type is seated in annular grooves 17 formed on the exterior of the tubular body, and is adapted to form a fluid-tight seal between the latter and the wellhead when the tubular body is inserted into the wellhead. A short distance below the lower annular groove 17, a reduced diameter tubular section 19 is formed and at its lower end is a male acme type thread 18 cut on the exterior of the reduced diameter tubular section 19. A shoulder 20 is defined where the tubular body 15 outside diameter reduces to the tubular section 19. An annular ring 21 is supported against shoulder 20 by springs 24. Threaded into the lower face 22 of this ring are a plurality of socket head cap screws 10 provided to retain an annular T-head dog retainer 23 in limited axial movement relative to the tubular section 19. A plurality of holes 25 are drilled through the retainer 23 to accommodate the cap screws. Counterbores 26 are provided in the lower face of the retainer large enough to provide clearance for the heads 27 of the cap screws and deep enough to provid for limited longitudinal travel of the cap screw heads within the counterbores. Mounted about each of the cap screw shanks 10 and pressing against the lower face of annular ring 21 and the upper face of the T-head dog retainer 23 are a plurality of springs 24. These springs resiliently urge the dog retainer 23 away from the lower annular ring to its full extended position where they are retained from further extension by the heads of the cap screws in the counterbores of the dog retainer. The reduced diameter tubular section 19 has an annular groove 28 in which is provided a snap ring stop 29 for the purpose of limiting the downward travel of the dog retainer 23, springs, cap screws and upper annular ring assembly.
Mounted in a plurality of T-heads formed in the lower end of the dog retainer 23 is a plurality of T-head dogs 30. The dogs are provided to latch the tubular body to the wellhead H. The T-head connection between the retainer :and the dogs allow for a limited radial movement of the dogs. A retainer cover ring 31 is provided over the T-head windows in the slip retainer to limit the radial outward movement of the T-heads of dogs 30.
Mounted about the tubular body and just below the dogs is a tapered head sleeve 32. The upper end of the sleeve 32 has an external tapered portion 33 that mates with an internal taper on the lower end of the slips. When the sleeve 32 moves upward on the mandrel, the tapered portion 33 causes the dogs to move radially outward. The lower end of the sleeve 32 is counterbored to form an internal shoulder 34a. A stop ring 36 is mounted in an external annular groove 35' on the tubular section 19. This stop ring serves to retain the cone on the tubular support allowing for a limited axial movement therewith.
A bearing support 37 is provided in the bottom surface of sleeve 32. A translatory member 41 is connected to the tubular body as for example, by the male acme threads 18 on the lower end of the tubular section 19 engaging mating box acme threads provided in the upper end of the translatory member. These connecting threads are preferably left-hand. A bearing support 39 is provided in the upper face of translatory member 41 adjacent support 37 of sleeve 32 and bearing rings 38 are provided in the supports 37 and 39. The connection between the translatory member 41 and the lower end of the tubular member 19 allows for relative axial movement between the two members which allows the sleeve 32 to set and unset the dogs as they are made up or unscrewed. A seal 42 is provided in the counterbore of the translatory member to seal off between the translatory member 32 and the tubular member 19.
In order to allow the translatory member to rotate in relation to the sleeve 32 and provide a bearing therebetween and at the same time connect these two members for axial travel, annular retainer is attached to the sleeve 32 with a suitable thread 44 and set screwed at 45. The lower end of the retainer 40 has a female flange member 46 that slips over the reduced diameter of the translatory member and retains the latter because of a male flange member 47 on the upper end of the translatory member. Between these two flanges are provided anti-friction rings 43.
Below the reduced diameter 48 on the translatory member, provided to form the male flange 47, a further reduced section 49 may be provided to allow clearance inside the upper end of a casing or liner 50 which may be set within the well-head H. Below reduced diameter 49 is another reduction 51 which provides space to mount seal or packing 52 which seals off between the latch member 19 and the liner 50. Packing ring 53 retains packing 52. Packing ring 53 has an outside diameter which allows clearance inside the liner and an inside diameter that clears reduced diameter 51.. Its end extends a slight distance below the lower end of the translatory member 41, to allow for compression of seal 52. The packing ring 53 is shear pinned to the translatory member and this pin 63 also shear pins the seal setting body 54 in the unset position.
The seal setting body 54 is attached to the translatory member by an acme left-hand thread 56 and the lower end of the seal setting body 'has a flange 55 that bears against the packing ring 53. On the upper outside diameter of the seal setting body is provided a male thread at a reduced diameter from the thread 56 for attaching an internally threaded stop ring 58. This stop ring limits the axial movement of the seal setting body. The stop ring 58 is set screwed from the upper face of this ring to the seal setting body by set screw 59. p
In operation, tubular body or mandrel 15 may be secured to the lower end of the drill string or a riser and lowered from the drilling structure for coupling to the wellhead H. The tubular body 15 is thus introduced into the bore of housing or wellhead H. The drill string and tubular body 15 may be guided into the wellhead H with conventional guide lines, or body 15 may be stripped over a drill pipe which may be left in the hole for this purpose. In either event, as the pipe string is lowered, the tubular body 15 having coupling device therein, is inserted in the bore of the wellhead H and lowered therein. As this occurs, the beveled upper inside diameter of the wellhead will guide the coupling device within its bore. The dogs 30 which are forced outwardly due to the springs forcing the dogs against the sleeve 32 will be forced to retracted position as the dogs land against the beveled portion 13 of the wellhead H. When the beveled shoulder 60 on the upper end of the coupling device seats on the mating bevel 13 of the wellhead, the dogs will be indexed longitudinally adjacent the annular groove 12 in the wellhead. As this occurs, the dogs will expand radially into this groove in latched relationship therewith as the springs expand the dogs against the tapered top of the sleeve 32. The drill string may then be picked up to check the locked position and prove that it is anchored. At this point the seal 52 has not yet been set nor has the axial play that is left between the coupling members been removed. To accomplish the foregoing a torsional gripping tool 57 is run adjacent the inner surface 62 of the seal setting member 54 and right-hand rotation is begun. The torsional gripping means -57 will grip the inner surface 62 and cause the setting member or sleeve 54 to rotate. This rotation causes the translatory member 41 to rotate also, as it is shear pinned to the seal setting member 62 by shear pin 63. As the translatory member 41 rotates to the right it will move upon threads 18 relative to the body 15, pushing the dogs 30 against the shoulder 12a in the housing. This position is shown in FIG. 2. As this occurs the rotation of the translatory member stops and shear pin 63 will be sheared from the seal ring 53 and the seal setting member 54. As this occurs the lefthand thread 56 will begin to make up and the upper face of flange 55 will shove the seal ring 53 upward setting seal 52 and thereby sealing off the tubular body 19 with the liner 50, or wellhead H when the liner is absent and the seal 52 is set directly against the inner surface of the wellhead. The tool is now fully set and the torsional gripping tool 57 is released and pulled from the hole.
To release the tool, the torsional gripping means 57 is rerun adjacent the surface 62 of the seal setting means and rotated to the left. This will cause the seal setting member 54 to move downward releasing the seal 52. As this occurs the lower face of the retainer nut 58 hits the left-hand acme thread and stops relative rotation between the seal setting member and' the translatory member. These members then rotate together causing the thread 18 to unscrew causing the translatory member to move downward. This causes the sleeve 32 to be pulled from under the dogs 30 until they reach the fully retracted position as shown in FIG. 3. The torsional tool 57 is now removed from the hole and the casing member may then be picked up, uncoupling the device so that it can be removed to the barge.
I claim:
1. An apparatus for latching a tubular body into the open end of a tubular member having an internal shoulder therein and internally mechanically releasing said body from said tubular member, comprising in combination:
means for supporting said tubular body within said tubular member,
a reduced diameter section of said tubular body forming an annular space between said tubular member and said body,
a movable dog in said annular space adjacent to said shoulder to prevent relative axial movement beween said tubular body and said tubular member,
means on said tubular body for retaining said dog thereon adjacent said shoulder when said tubular body is supported within said tubular member,
a translatory member threadably engaging said body below said dog,
means associated with said translatory member for holding said dog radially outward against said shoulder, and
means internal with respect to said tubular body and said translatory member for rotating said translatory member relative to said tubular body to drive said holding means upwardly against said dog to move said dog until said dog engages the top of said shoulder, said holding means retaining said dog radially outwardly in said shoulder and against the top of said shoulder.
2. The apparatus of claim 1 including in said combination, a sleeve engageable with said translatory member and wherein said rotating means includes means for engaging said sleeve.
3. An apparatus for latching a tubular body into the open end of a tubular member having an internal shoulder therein and internally mechanically releasing said body from said tubular member, comprising in combination:
means for supporting said tubular body within said tubular member,
a reduced diameter section of said tubular body forming an annular space between said tubular member and said body,
a movable dog in said annular space adjacent said shoulder to prevent relative axial movement between said tubular body and said tubular member when said dog is engaged in said shoulder,
spring means on said tubular body for retaining said dog thereon adjacent said shoulder when said tubular body is supported within said tubular member,
a translatory member threadably engaging said body below said dog,
tapered means associated with said translatory member for holding said dog radially outward against said shoulder, and,
means internal with respect to said tubular body and said translatory member relative to said tubular body to drive said taper means upwardly against said dog to move said dog until said dog engages the top of said shoulder, said tapered shoulder means retaining said dog radially outwardly in said shoulder and against the top of said shoulders.
.4. An apparatus for latching a tubular body into the open end of a tubular member having an internal shoulder therein and internally mechanically releasing said body from said tubular member, comprising in combination:
means for supporting said tubular body within said tubular member,
a reduced diameter section of said tubular body forming an annular space between said tubular member and said body,
a movable dog in said annular space adjacent said shoulder,
means on said tubular body for retaining said dog thereon adjacent said shoulder when said tubular body is supported within said tubular member,
a translatory member threadably engaging said body below said dog,
tapered means associated with said translatory member for holding said dog radially outward against said shoulder,
a packer setting sleeve threadably engaging said translatory member,
an extrudable packer between said setting sleeve and said tubular member,
internal means for rotating said translatory member with said sleeve to drive said taper means upwardly against said dog until said dog engages the top of said shoulder, said tapered means retaining said dog radially outwardly in said shoulder and against the top of said shoulder, and
means for preventing relative movement between said translatory member and said sleeve while said translatory member and sleeve are moving upwardly with respect to said tubular body, until said dog engages the top of said shoulder, said movement preventing means being shearable upon further rotation of said setting sleeve after said dog engages the top of said shoulder whereupon said sleeve moves upwardly relative to said translatory member to set said packer.
5. The apparatus of claim 4 wherein said extrudable packer is positioned between said setting sleeve and an open ended well casing hung in said tubular body and said packer is set between said sleeve and said casing.
6. An apparatus for latching a tubular body into the open end of a tubular member and internally mechanically releasing said body from said tubular member, comprising in combination:
means for supporting said tubular body within said tubular member,
a reduced diameter section of said tubular body forming an annular space between said tubular member and said body,
means in said annular space movable relative to said tubular body for securing said tubular body to said tubular member to prevent relative axial movement between said tubular body and said tubular member,
a translatory member threadably engaging said body,
means movable by said translatory member for holding said securing means radially outward against the internal surface of said tubular member,
means internal with respect to said tubular body, and
said translatory member for rotating said translatory member relative to said tubular body to drive said holding means upwardly against said securing means to move said securing means radially outwardly against the internal surface of said tubular member,
said holding means retaining said securing means radially outwardly against the internal surface of said tubular member.
7. The apparatus of claim 6 including in said combination, a sleeve engageable with said translatory member and wherein said moving means includes means for engaging said sleeve.
8. The apparatus of claim 7 wherein said sleeve engaging means is a torsional gripping means.
9. An apparatus for latching a tubular body into the open end of a tubular member and internally mechanically releasing said body from said tubular member, comprising in combination:
means for supporting said tubular body within said tubular member,
a reduced diameter section of said tubular body forming an annular space between said tubular member and said body,
means in said annular space movable relative to said tubular body for securing said tubular body axially with respect with said tubular member,
a translator member threadably engaging said body below said securing means,
tapered means movable by said translatory member for holding said securing means radially outward against the inner surface of said tubular member,
a packer setting sleeve threadably engaging said translatory member,
an extrudable packer between said setting sleeve and said tubular member,
internal means for rotating said translatory member with said sleeve to drive said taper means upwardly upwardly relative to said translatory member to set against said securing means until said securing means said packer. engage the inner surface of said tubular member, said References Cited tapered means retaining said securing means radially UNITED STATES PATENTS outward against said tubular member, and 5 means for preventing relative movement between said 10/1958 Thaxton X translatory member and said sleeve while said trans- 3,051,244 8/1962 Lltchfield 285*18 X latory member and sleeve are moving upwardly with 3,074,746 1/1963 Shames at 285 8 respect to said tubular body, until said securing 3,147,992 9/1964 Haeber 3L 28518 means engage the inner surface of said tubular 10 3,222,089 12/1965 oiteman 285-48 member in securing relationship, said movement pre- 3,273,915 9/1966 BlshoP et 285315 venting means being shearable upon further rotation 1,529,607 3/1925 Owan 166 217 of said setting sleeve after said securing means engage the inner surface of said tubular member in CARL TOMLIN Primary Examiner securing engagement whereupon said sleeve moves 15 D. W. AROLA, Assistant Examiner
US456968A 1965-05-19 1965-05-19 Remote underwater wellhead connector Expired - Lifetime US3521909A (en)

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Publication number Priority date Publication date Assignee Title
FR2316522A1 (en) * 1975-06-30 1977-01-28 Erap CONNECTION DEVICE FOR SUCCESSIVE PORTIONS OF PIPES, ESPECIALLY FOR SUBMERSIBLE OIL PIPES
US4307902A (en) * 1979-07-13 1981-12-29 Otis Engineering Corp. Riser connector
EP0109541A1 (en) * 1982-10-14 1984-05-30 Fmc Corporation Pipe string tie-back connector
US4489472A (en) * 1978-11-28 1984-12-25 Societe Nationale Elf Aquitaine Connection-disconnection device between one rigid pipe, inside well-tubing connected to a base by an articulated coupling, and another rigid pipe fixed to this base
US4497510A (en) * 1980-11-23 1985-02-05 Societe Nationale Elf Aquitaine (Production) Connection-disconnection device between one rigid pipe, inside well-tubing connected to a base by an articulated coupling, and another rigid pipe fixed to this base
US4499950A (en) * 1983-05-27 1985-02-19 Hughes Tool Company Wellhead stabilization
US4653172A (en) * 1985-02-05 1987-03-31 Westinghouse Electric Corp. Axial clamp for nuclear reactor head penetration conoseal joints
US4699215A (en) * 1986-08-18 1987-10-13 Hughes Tool Company External tie-back connector
US4872708A (en) * 1987-05-18 1989-10-10 Cameron Iron Works Usa, Inc. Production tieback connector
US5247996A (en) * 1991-11-15 1993-09-28 Abb Vetco Gray Inc. Self preloading connection for a subsea well assembly
US5924741A (en) * 1996-09-06 1999-07-20 Alcatel Weaklink device for elongated offshore articles
US20030094284A1 (en) * 2001-11-21 2003-05-22 Fenton Stephen Paul Internal connection of tree to wellhead housing
US20090277645A1 (en) * 2008-05-09 2009-11-12 Vetco Gray Inc. Internal Tieback for Subsea Well
US20090308658A1 (en) * 2008-06-16 2009-12-17 Larson Eric D Latch system for friction-locked tubular members

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US1529607A (en) * 1923-05-10 1925-03-10 James L Bales Circulating and cement head
US2855003A (en) * 1956-01-11 1958-10-07 Ellis B Thaxton Pipe stoppers
US3074746A (en) * 1959-11-16 1963-01-22 Sidney J Shames Jaw-type expansion adapter for fluid conduits
US3051244A (en) * 1960-03-22 1962-08-28 Baker Oil Tools Inc Well liner running and supporting apparatus
US3147992A (en) * 1961-04-27 1964-09-08 Shell Oil Co Wellhead connector
US3222089A (en) * 1962-11-09 1965-12-07 Shell Oil Co Secondary release mechanism for fluid actuated couplings
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Cited By (25)

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Publication number Priority date Publication date Assignee Title
FR2316522A1 (en) * 1975-06-30 1977-01-28 Erap CONNECTION DEVICE FOR SUCCESSIVE PORTIONS OF PIPES, ESPECIALLY FOR SUBMERSIBLE OIL PIPES
US4087119A (en) * 1975-06-30 1978-05-02 Societe Nationale Elf Aquitaine (Production) Fluid pressure operated duct coupling
US4489472A (en) * 1978-11-28 1984-12-25 Societe Nationale Elf Aquitaine Connection-disconnection device between one rigid pipe, inside well-tubing connected to a base by an articulated coupling, and another rigid pipe fixed to this base
US4307902A (en) * 1979-07-13 1981-12-29 Otis Engineering Corp. Riser connector
US4497510A (en) * 1980-11-23 1985-02-05 Societe Nationale Elf Aquitaine (Production) Connection-disconnection device between one rigid pipe, inside well-tubing connected to a base by an articulated coupling, and another rigid pipe fixed to this base
EP0109541A1 (en) * 1982-10-14 1984-05-30 Fmc Corporation Pipe string tie-back connector
US4499950A (en) * 1983-05-27 1985-02-19 Hughes Tool Company Wellhead stabilization
US4653172A (en) * 1985-02-05 1987-03-31 Westinghouse Electric Corp. Axial clamp for nuclear reactor head penetration conoseal joints
US4699215A (en) * 1986-08-18 1987-10-13 Hughes Tool Company External tie-back connector
US4872708A (en) * 1987-05-18 1989-10-10 Cameron Iron Works Usa, Inc. Production tieback connector
US5247996A (en) * 1991-11-15 1993-09-28 Abb Vetco Gray Inc. Self preloading connection for a subsea well assembly
US5924741A (en) * 1996-09-06 1999-07-20 Alcatel Weaklink device for elongated offshore articles
US20030094284A1 (en) * 2001-11-21 2003-05-22 Fenton Stephen Paul Internal connection of tree to wellhead housing
GB2382366A (en) * 2001-11-21 2003-05-28 Vetco Gray Inc Abb A subsea wellhead assembly having a production tree and a method of completing a subsea well
GB2382366B (en) * 2001-11-21 2005-11-16 Vetco Gray Inc Abb Internal connection of tree to wellhead housing
US6978839B2 (en) 2001-11-21 2005-12-27 Vetco Gray Inc. Internal connection of tree to wellhead housing
US20090277645A1 (en) * 2008-05-09 2009-11-12 Vetco Gray Inc. Internal Tieback for Subsea Well
US7896081B2 (en) * 2008-05-09 2011-03-01 Vetco Gray Inc. Internal tieback for subsea well
US20110155382A1 (en) * 2008-05-09 2011-06-30 Vetco Gray Inc. Internal Tieback for Subsea Well
US8127853B2 (en) * 2008-05-09 2012-03-06 Vetco Gray Inc. Internal tieback for subsea well
US20090308658A1 (en) * 2008-06-16 2009-12-17 Larson Eric D Latch system for friction-locked tubular members
US7913767B2 (en) * 2008-06-16 2011-03-29 Vetco Gray Inc. System and method for connecting tubular members
US20110174495A1 (en) * 2008-06-16 2011-07-21 Vetco Gray Inc. Latch System for Friction-Locked Tubular Members
US8312933B2 (en) * 2008-06-16 2012-11-20 Vetco Gray Inc. Marine drilling riser system
AU2009268999B2 (en) * 2008-06-16 2015-01-22 Vetco Gray, Inc. Latch system for friction-locked tubular members

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