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 
       [0001]    This invention relates to the general subject of monitoring the current in the ocean from a floating vessel 
       CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0002]    Not applicable. 
       STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
       [0003]    Not applicable 
       REFERENCE TO A “MICROFICHE APPENDIX” 
       [0004]    Not applicable 
       BACKGROUND OF THE INVENTION 
       [0005]    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. 
         [0006]    These connections can be made by divers, by ROVs (Remotely Operated Vehicles) which are free swimming, or by manipulators which are guided into place. 
         [0007]    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. 
         [0008]    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. 
         [0009]    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. 
         [0010]    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. 
         [0011]    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. 
         [0012]    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. 
         [0013]    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. 
         [0014]    The hydraulic stab sub of &#39;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 &#39;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. 
         [0015]    Consequently, those of skill in the art will appreciate the present invention which addresses the above and other problems. 
       BRIEF SUMMARY OF THE INVENTION 
       [0016]    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. 
         [0017]    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. 
         [0018]    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 
         [0019]      FIG. 1  is a view of a semi-submersible drilling facility showing the vessel, the drilling riser, and the current measuring device. 
           [0020]      FIG. 2  is an elevational view, in section, showing insertion of a prior art hydraulic stab sub into a receptacle. 
           [0021]      FIG. 3  is an elevational view, in section, showing removal of a prior art hydraulic stab sub under pressure from a receptacle. 
           [0022]      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. 
           [0023]      FIG. 4B  is a side view of the composite sealing ring of  FIG. 4A . 
           [0024]      FIG. 5  is a graphic showing a composite seal in accord with the present invention in the non-energized or non-activated state. 
           [0025]      FIG. 6  is a graphic similar to  FIG. 5 , with the composite seal activated or energized. 
           [0026]      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. 
           [0027]      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. 
           [0028]      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 
       [0029]    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 . 
         [0030]    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. 
         [0031]    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. 
         [0032]    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. 
         [0033]    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. 
         [0034]    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 . 
         [0035]    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 . 
         [0036]    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. 
         [0037]    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. 
         [0038]      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 . 
         [0039]    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. 
         [0040]    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. 
         [0041]    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. 
         [0042]    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. 
         [0043]    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. 
         [0044]    Referring now to  FIG. 7  receptacle  100  has seal bores  102  and  104 , entrance chamfer  106  and fluid port  108 . 
         [0045]    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 . 
         [0046]    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. 
         [0047]    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 . 
         [0048]    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 . 
         [0049]    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. 
         [0050]    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 . 
         [0051]    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 . 
         [0052]    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. 
         [0053]    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.