US20120168167A1

US20120168167A1 - Blowout resistant frictionless hydraulic connector

Info

Publication number: US20120168167A1
Application number: US12/930,298
Authority: US
Inventors: Benton Frederick Baugh
Original assignee: Individual
Current assignee: TULSA POWER LICENSING CORP
Priority date: 2011-01-04
Filing date: 2011-01-04
Publication date: 2012-07-05

Abstract

The method of providing a hydraulic stab sub for sealing in a receptacle bore of a first diameter comprising providing the hydraulic stab subs with two or more composite seals each having two metal rings having an outer second diameter less than the first diameter and an inner third diameter and bonding a resilient material between the two metal rings with an outer seal diameter less that the first diameter and an inner seal diameter less than the inner third diameter, providing a seal expander having an expander outside diameter which is smaller than the third inner diameter and greater than the seal inner diameter, such that when the hydraulic stab sub is within the receptacle bore and the seal expander is moved to within the inner seal diameter of the composite seals, the resilient material is expanded into sealing engagement with the receptacle bore.

Description

TECHNICAL FIELD

This invention relates to the general subject of monitoring the current in the ocean from a floating vessel

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable

REFERENCE TO A “MICROFICHE APPENDIX”

Not applicable

BACKGROUND OF THE INVENTION

As offshore drilling and completion operations progress into deeper waters, especially in depths of water greater than 1000 feet, many relatively simple surface operations become complex and costly. One frequent operational requirement is that of engaging a hydraulic stab sub receptacle with a probe for the purpose of applying hydraulic flow and pressure to operate a function. The function can be a valve, blowout preventer, test port or other such items.
These connections can be made by divers, by ROVs (Remotely Operated Vehicles) which are free swimming, or by manipulators which are guided into place.
These type operations have seen a history of field problems in that the force of insertions is somewhat unpredictable depending on a number of factors such as percent squeeze of the seals, surface finishes, shape of entrance chambers, hardness of the seal members, cross sectional area of the seal members, and the outer diameter of the seal members.
Industry standards are being developed through the American Petroleum Institute which should provide a maximum of 30-50 lbs of insertion force, a number which will not allow the insertion of most stab subs manufactured at the present time.
A further complication to this is that if a significant amount of remote capability is to be gained, more than one stab sub needs to be engaged at an interface to allow multiple control functions. In some cases as many as twenty four functions are being considered at a time, each of which require hydraulic control through a stab sub. The potential forces to be required to handle multiple insertions such as these are clearly in excess of the horizontal forces available from free swimming vehicles or divers.
A further complication to the remote stabbing tools is that for many of the subsea systems, a 20 year life expectancy is desired for the tooling. This means that the surface finish of the subsea receptacles can be questionable after prolonged exposure. Even when protectors have been in place for 20 years, the protected surfaces would be suspect.
A further complication is that if the stab subs are removed from the receptacles without the pressure being removed, the seals are prone to be damaged and/or literally blown out of the seal groove where they are supposed to be. In addition to potential damage and the potential lack of safety from operations with failed seals, trips back to the surface to replace these seals are time consuming and therefore expensive. Some of the offshore operations cost as much as one million dollars per day.
Adequate secondary control for subsea operations has long been needed and has been considered to be not available because of the lack of the ability of the subsea remotely operated vehicles from handling multiport stabbing profiles.
U.S. Pat. No. 4,863,314, to the present inventor, issued Sep. 5, 1989, discloses a hydraulic stab sub with multiple seal especially for use in remote and harsh environments with the ability to move the seals radially inward to a retracted position in which the hydraulic stab sub can be easily inserted into a mating receptacle and alternately to move the seals radially outward to perform useful functions such as sealing or locking into the receptacle. U.S. Pat. No. 4,863,314 is incorporated herein by reference.
The hydraulic stab sub of '314 provides an exemplary solution for the problem of insertion of multiple seals utilizing only a very limited sub insertion force required, which can be applied by free swimming ROVs and divers. However, during removal of the hydraulic stab sub of '314, pressure in the lines that is applied to the moveable seals can subject the seals to potentially damaging or pinching movement under certain conditions.
Consequently, those of skill in the art will appreciate the present invention which addresses the above and other problems.

BRIEF SUMMARY OF THE INVENTION

The object of this invention is to provide a subsea hydraulic stab connector which can be inserted with pressure energized seals without requiring insertion force to compress the seals.
A second object of this invention is to provide a subsea hydraulic stab connector which the seals can be released from a sealing bore without first removing the pressure within the stab connector and without causing damage to the seals or causing the seals to move out of the seal grooves.
A third object of this invention is to provide a connector which can be locked in place after the seals are set.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a view of a semi-submersible drilling facility showing the vessel, the drilling riser, and the current measuring device.

FIG. 2 is an elevational view, in section, showing insertion of a prior art hydraulic stab sub into a receptacle.

FIG. 3 is an elevational view, in section, showing removal of a prior art hydraulic stab sub under pressure from a receptacle.

FIG. 4A is an enlarged elevational view, in section, of a composite sealing ring in accord with one possible embodiment of the present invention in the non-activated state.

FIG. 4B is a side view of the composite sealing ring of FIG. 4A.

FIG. 5 is a graphic showing a composite seal in accord with the present invention in the non-energized or non-activated state.

FIG. 6 is a graphic similar to FIG. 5, with the composite seal activated or energized.

FIG. 7 is an elevational view of a hydraulic stab sub showing the seals in a non-activated state for frictionless removal or insertion from the bore of the receptacle in accord with a possible embodiment of the present invention.

FIG. 8 is an elevational view of a hydraulic stab sub showing the seals activated and having sealing engagement with the bore of the receptacle and the locking ring engaged.

FIG. 9 is an elevational view of a hydraulic stab sub showing the seals in a non-activated state and the hydraulic stab sub partially removed from the bore of the receptacle illustrating that the seals will not be damaged or blown out of their intended position as was illustrated in FIG. 3.

DETAILED DESCRIPTION OF THE INVENTION

Referring now to FIG. 1, a vessel 10 is shown floating upon the surface 11 of the body of water 12. A riser assembly 13 extends downwardly from the vessel 10 towards the bottom 14 of the body of water 12. The lower elements of the riser assembly 13 consist, in this example, of a subsea wellhead assembly 20 typically positioned on or near the bottom 14 of the body of water 12. Extending downward into the earth formation for drilling and completion operation is housing assembly 21 which suspends one or more strings of casing and is landed on landing base 22.
It will be understood that the term subsea wellhead assembly is meant to include any assemblage of components either fixedly or removably secured to the top of the housing assembly 21, either during the drilling, completion, production, reworking or maintenance of a well. Thus, during the drilling of a well, the subsea wellhead assembly may comprise certain components such as blowout preventers, valves connectors, and the like.
The subsea wellhead assembly 20 comprises various components such as a hydraulically operated connector 23 and hydraulically actuated valves 24 and 25 which are actuated by valve actuators 26 and 27 respectively. The operator 28 for the connector 23 is typically made integrally with the connector.
Receptacles 30, 31 and 32 are provided for receiving hydraulic flow and pressure to operate connector 23 and valves 24 and 25 respectively. Receptacles 31 and 32 are connected to valves 24 and 25 through shuttle valves 33 and 34. Shuttle valves 33 and 34 are further connected to a control means 35 through hoses 36 and 37. Control means 35 is connected by control hoses 38 to the surface. Normal control of these functions is through the control means 35 from the surface; when required secondary or emergency control can be achieved by pressuring through the receptacles. The shuttle valves 33 and 34 prevent the signal from one shuttle valve port to communicate with the opposite shuttle valve port, as is well known in the industry.
Receptacle 30 is connected to the hydraulically operated connector 23 by hose 39 and is not operated redundantly from the surface. In this example, the only means of operating this connector is through the receptacle.
ROV 40 is shown with a manipulator arm 41, a hydraulic stab sub 42, hose 43 which receives hydraulic and/or electric power from the surface to operate the ROV and hose 44 which receives hydraulic power from the surface for the hydraulic stab sub 42.
On the vessel 10 at the surface the hose 43 connects to reel 45 and the hose 44 connects to the reel 46. Both reel 45 and reel 46 is shown connected to the hydraulic accumulator skid 47.
Referring now to FIG. 2, conventional O-ring type seal 50 is shown within groove 52 of stab 54, sealingly engaging the bottom 56 of groove 52 and the seal bore 58 of receptacle 60. It can be seen that the original round shape of the O-Ring type seal is deformed to an oval shape as it is squeezed so it will seal against the surfaces. Seal 62 in groove 64 is approaching chamfer 66, and as it moves along chamfer 66 it is compressed to a shape similar to seal 50. In practice a remotely operated subsea vehicle can provide the force to compress one or two of these seals, but when controls involving 10-30 functions are required this is simply not workable.
Referring now to FIG. 3, stab 54 is being removed to the right on the figure from receptacle 60 without the pressure being vented. As the seal 62 moves along the chamfer 66, it is literally pushed out of groove 64 by pressure and is damaged or lost. This can be a very expensive mistake in 10,000 feet of ocean depths.
FIG. 4A and FIG. 4B show a composite seal ring, which may comprise seal 70, in a non-activated state. Seal 70 comprises resilient material 72 such as Buna N Hycar of 70 to 90 durometer hardness bonded between two metal rings 74 and 76. In the non-activated state, the outer diameter 78 of resilient material 72 is preferably approximately the same as the outer diameter of metal rings 74 and 76. However, the outer diameter 78 could be slightly recessed, be the same as, or could be slightly greater than the outer diameter of metal rings 74 and 76. In one embodiment, the outer diameter 78 of resilient material 72 is no more than five thousandth of an inch greater than the outer diameters of metal rings 74 and 76. In one embodiment, excessive resilient material molded or bonded between the metal rings which is greater than the diameters of metal rings 74 and 76 may be removed by a desired amount. For example, any excessive resilient material may be removed by a lathe to be substantially equal to the outer diameter of metal rings 74 and 76.
For convenience, any difference between outer diameter 78 of resilient material 72 and the outer diameter of rings 74 and 76 is referred to as an outer diameter offset. If outer diameter 78 is the same as then outer diameter of rings 74 and 76, then the outer diameter offset is zero. If the outer diameter 78 is less than the outer diameter of rings 74 and 76, the outer diameter offset is negative. Thus, the outer diameter offset between outer diameter 78 and the outer diameters of rings 74 and 76 can be positive, negative, or zero.
The inner diameter 80 of resilient material 72 is smaller than the inner diameters 82 and 84 of metal rings 74 and 76 by an amount that may be referred to as an inner offset, such as inner diameter offset 86. In one embodiment, inner diameter 80 may be about 30 or 40 thousandth of an inch less than the inner diameters 82 and 84 of metal rings 74 and 76. This amount can be selected to produce a desired amount of expansion capability with the understanding that too much or too little expansion capability may not be desirable.
In a preferred embodiment, in the non-activated state, the outer diameter offset as defined above, is less than, and preferably considerably less than the inner diameter offset. For example, the inner diameter offset might be thirty thousandth of an inch while the outer diameter offset is one thousandth of an inch, making the inner diameter offset thirty times greater than the outer diameter offset.
Referring now to FIG. 5, mandrel 90 is shown approaching composite seal 70. The outer diameter 92 of mandrel 90 is smaller than the internal diameters 82 and 84 but larger than inner diameter 74 of resilient material 72. The volume of resilient material 72 bonded to metal rings 74 and 76 is such that radially outward force engaging the inner diameter 80 activates outer diameter 78 to move or be urged radially outwardly into sealing engagement with the sealing surface. This produces an outer offset 94 (seen in FIG. 6) which will insure that surface 78 will sealingly engage the inner bore of a receptacle, such as receptacle 60. The side surfaces 86 and 88 of seal 70, which are bonded to metal rings 74 and 76 do not move in the radial direction.
Referring now to FIG. 6, mandrel 90 is engaged with seal 70, causing the inner diameter 80 and therefore outer diameter 78 of resilient material 72 to become larger, as discussed above. When appropriately within a seal bore, the outer diameter 78 of seal material 72 will engage the seal bore, stopping further enlargement and will require that that the seal expand in the left and right directions.
Referring now to FIG. 7 receptacle 100 has seal bores 102 and 104, entrance chamfer 106 and fluid port 108.
Stab sub 110 has 2 seals 70, mandrel 112 with chamfers 114 and 116 and seal diameters 118 and 120, body 122, fluid port 124, retaining nut 126, internal seal 128 and 130, lock ring 132 and retaining nose 134. Mandrel 112 has a hole 136 which can be engaged to move the mandrel 112 to the left from the position as shown in this figure and then back to the present position. Lock ring 132 has outer diameter 138 which is eccentric from inner diameter 140 such that when retaining nose 134 is engaged by mandrel 112, the outer diameter is forced to be eccentric to the centerline of the body 122 and prevent the removal of the stab sub 110 from the receptacle 100.
The outer diameter 78 (See FIG. 4A) of seal rings 70 and outer diameter 138 of lock ring 132 are a smaller diameter than the bores 102 and 104 of receptacle 100, so the stab sub 110 can be inserted into the receptacle 100 without seal or lock ring friction.
Referring now to FIG. 8 hole 136 and therefore mandrel 112 have been moved to the left and seal diameters 118 and 120 have been moved under the seals 70 as was seen in FIG. 6. This has forced the outer diameters 78 into sealing engagement with the seal bores 102 and 104. The movement of mandrel 112 has happened after the stab sub 110 was inserted into receptacle 100, and is preferable done by a hydraulic cylinder interconnected to hole 136.
Lock ring 132 is moved to an eccentric position such that a portion of the outer diameter 138 is radially further from the centerline of the body 122 than the bore 104 of the receptacle. This means that the stab sub 110 is effectively mechanically locked into the receptacle 100.
In this position, the stab sub 110 is ready to receive pressurized fluid into port 124 for delivery out of port 108 on receptacle 100 to do useful work on a subsea blowout preventer stack or other subsea installation.
Referring now to FIG. 9 hole 136 was moved back to the original position to the right and the stab sub 110 is removed from the receptacle 100 to the position which simulates what was observed in FIG. 3. As the outer diameter 78 of seal ring 70 returned to the original smaller diameter when diameter 118 was moved from being within the seal ring and as the resilient material 72 is bonded to metallic rings 74 and 76 as seen in FIG. 4A, the seal 70 is prevented from being blown out by fluid flow as is indicated by arrows 150-156.
The movement of the mandrel away from the lock ring 132 also allowed the inner diameter 140 to become eccentric so that outer diameter 138 can become concentric, allowing the stab sub 110 to be removed from receptacle 100.
Accordingly, the present invention eliminates the costly problems of stab subs that have been utilized by divers and ROVs (remotely operated vehicles), which have had seals such as are illustrated in FIG. 3, for over 50 years, wherein operators have simply endured the inconvenience and risk of losing seals when pulled under pressure and in some cases simply being inserted.
The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the invention. Accordingly, the protection sought herein is as set forth in the claims below.

Claims

1. The method of providing a hydraulic stab sub for sealing in a receptacle bore of a first diameter comprising:

providing said hydraulic stab subs with two or more composite seals each having two metal rings having an outer second diameter less than said first diameter and an inner third diameter and bonding a resilient material between said two metal rings with an outer seal diameter less that said first diameter and an inner seal diameter less than said inner third diameter,

providing a seal expander having an expander outside diameter which is smaller than said third inner diameter and greater than said seal inner diameter,

such that when said hydraulic stab sub is within said receptacle bore and said seal expander is moved to within said inner seal diameter of said composite seals, said resilient material is expanded into sealing engagement with said receptacle bore.

2. The method of claim 1 further comprising a lock ring with a lock ring inner diameter which is eccentric to a lock ring outer diameter such that when said expanded engages said lock ring inner diameter a portion of said lock ring outer diameter has a radial extent greater than the radial extent of said first diameter.

3. A hydraulic stab sub, which is insertable into a receptacle bore, comprising:

a composite seal mounted around said hydraulic stab sub which is operable between an activated state for sealing engagement with said receptacle bore and a non-activated state for insertion and removal of said composite seal with respect to said receptacle bore, said composite seal comprising an inner ring of resilient material, said inner ring of resilient material being bonded on opposite sides between two metal rings, in said non-activated state said inner ring of resilient material comprising a resilient material inner diameter less than an inner diameter of said two metal rings wherein a difference between said resilient material inner diameter and said inner diameter of said two metal rings is an inner diameter offset, said resilient material comprising a resilient material outer diameter wherein a difference between said resilient material outer diameter and an outer diameter of said two metal rings is an outer diameter offset, and wherein in said non-activated state said inner diameter offset is greater than said outer diameter offset;

a seal expander comprising a seal expander outer diameter which is smaller than said inner diameter of said two metal rings and larger than said resilient material inner diameter, said seal expander being moveable such that when said composite seal is positioned within said receptacle bore and said seal expander is moved to within said resilient material inner diameter to place said composite seal in an activated state, then said resilient material is expanded into sealing engagement with said receptacle bore.

4. The method of claim 3 further comprising a lock ring with a lock ring inner diameter which is eccentric to a lock ring outer diameter such that when said seal expander engages said lock ring inner diameter a portion of said lock ring outer diameter has a radial extent greater than the radial extent of said first diameter.