Patent Publication Number: US-11041365-B2

Title: Annular controlled safety valve system and method

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of and priority to U.S. Provisional Patent Application No. 62/679,396 filed on Jun. 1, 2018, which is incorporated herein by reference. 
    
    
     BACKGROUND OF THE DISCLOSURE 
     The present disclosure relates to an annular controlled safety valve (ACSV) system and method, and more particularly, to the annular pressure control of the ACSV in a remedial application. 
     SUMMARY 
     Aspects described herein provide a system for operating a downhole system in a wellbore having pressure inlet ports formed in the production tubing, the one or more pressure inlet ports extending through the production tubing between the annular area and the outer surface of the conduit, the one or more pressure inlet ports being situated below a first top sealing device relative to the conduit. The system includes an annular pressure control valve coupled to a metal conduit below the one or more pressure inlet ports in the wellbore, the annular pressure control valve being configurable in an open position and in a closed position, where the annular pressure control valve transitions between the closed position and the open position responsive to the annular pressure. The system includes a second bottom sealing device coupled to a bottom portion of the conduit below the annular pressure control valve. 
     In normal practice, oil/gas wells (especially offshore) have a sub-surface control safety valve (SSCSV) in the tubing string which is operated via a hydraulic control line running from the wellhead to the SSCSV. A prior-art system that includes a conventional SSCSV  60  is shown in  FIGS. 1A and 1B . The SSCSV  60  is opened and closed by the application and removal of pressure down the hydraulic control line. The SSCSV  60  is a safety mechanism used for emergency shut-off of the producing well at a point below the mudline should the need arise ((e.g. a hurricane topples the platform rendering the wellhead with its manual (or automatic) valves useless)). 
     Over an extended time period during the course of producing the well, it is not unusual for a hole(s) to develop in the production tubing string causing the flowing or shut-in well pressure to be present in the annular area between the production tubing and the well casing. This would normally require an expensive well workover operation to pull and replace the damaged production tubing. Alternatively, a tubing patch or straddle with a smaller diameter pipe could be run inside the production tubing across the damaged section of tubing. However, if necessary to run the tubing patch (liner) or straddle across the interval where the SSCSV  60  is placed would eliminate the functionality of the SSCSV  60  thereby losing the ability for emergency well control. 
     Other reasons for placement of a liner pipe through an existing production tubing with SSCSV  60  may be for improved production from the well such as a velocity string or installation of gas lifting ability. It may also be to allow continued production in a well where the SSCSV  60  has malfunctioned, possibly due to scale or loss of sealing ability. 
     The present disclosure addresses the drawbacks described above by providing a downhole safety control valve operated responsive to the annular pressure inside of the well. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIGS. 1A and 1B  are partial cross-sectional views of a prior art sub-surface safety control valve in position in production tubing. 
         FIGS. 2A and 2B  are cross-section views of an embodiment of downhole system of the present disclosure in position in production tubing. 
         FIG. 3  is a cross-sectional view of an embodiment of the control valve of the present disclosure in open position. 
         FIG. 4  is a cross-sectional view of the embodiment of the control valve shown in  FIG. 3  in closed position. 
         FIG. 5  is a view of an embodiment of an inlet port of the present disclosure. 
         FIG. 6  is a view of an embodiment of an inlet port of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION OF THE DISCLOSURE 
     The present disclosure addresses the above drawbacks by providing a downhole system in a wellbore having an annular pressure control safety valve operated based on an annular pressure associated with a completion. For example, aspects disclosed herein provide a manner of having a safety valve in a wellbore when an original SSCSV has been rendered useless by corrosion, flow cutting, or a hole in tubing above the SSCSV that allows production to bypass the SSCSV (or other reason the SSCSV is unusable). 
     As shown in  FIGS. 2-6 , the downhole system  2  may extend in a wellbore  4  and may include an elongated tubular conduit  6 , production tubing  8 , production casing  10 , a first top packer  14 , an upper hang-off sub assembly  56 , an annular pressure control valve  34 , an upper stiff pup joint  36 , a first sealing anchor latch  38 , a first upper anchor assembly  40 , a lower hang-off sub assembly  42 , a lower stiff pup joint  58 , a second sealing anchor latch  44 , and a second bottom packer  46 . The system  2  may also include a wellhead  52  and a casing valve  54 . 
     In some embodiment, a stiff pup joint  36  may be coupled to the metal conduit  6  below the pressure control valve  34 . A first sealing anchor latch  38  may be coupled to the metal conduit  6  below the stiff pup joint  36 . A first upper anchor hanger assembly  40  having a dual seal bore may be coupled to the metal conduit  6  below the sealing anchor. A hang-off sub assembly  42  may be coupled to the metal conduit  6  below the first upper anchor hanger assembly  40 . A second sealing anchor latch  44  may be coupled to the metal conduit  6  below the hang-off sub assembly  42 . A second bottom packer  46  may be coupled to a bottom portion  20  of the conduit  6  below the second sealing anchor latch  44 . In some embodiments, the bottom portion  20  of the conduit  6  may be located in a midsection  24  of the wellbore  4 . 
     The conduit  6  (e.g., pipe, liner, patch, or straddle) may be coupled to the pressure control valve  34 , which may be operated downhole in the wellbore  4 . The conduit  6  may be any material suitable for operating in a downhole well. In one embodiment, the conduit  6  may be metal. The placement of the conduit  6  through an existing production tubing  8  with a SSCSV  60  may result in improved production from the well such as via a velocity string or installation of gas lifting ability. According to some aspects, the pressure control valve  34  may allow continued production in a well where the SSCSV  60  may have malfunctioned, such as due to scale or loss of sealing ability. 
     According to some aspects, the system  2  may include a conduit  6  with a annular controlled safety valve  34  (ACSV) that is sealed in two places (one above and one below the ACSV  34 ) inside the production tubing  8  (or the “casing” if it is a monobore completion that does not have production tubing  8 ). The two seals may be provided by any sealing mechanism or device. For example, a dual seal bore packer (e.g., packer  14  or packer  46 ) may be used to provide the seal. The dual seal bore packer may be a tool that may have an elastomeric element that is energized to create a seal. The dual seal bore packer may also have an anchor (e.g., anchor latch  38  or  44 ) that holds the packer  14  or  46  in position in the tubing  8  and is usually capable of supporting a certain amount of weight (as in the conduit  6 ). A sealing anchor latch device  38  or  44  can be landed into the top of the DSB packer  14  or  46 . The bottom end of the packer  14  or  46  allows for coupling of other devices. The dual seal bore allows the packer  14  or  46  to be located and sealed in different places along the tubing  8  and may allow the packer  14  or  46  to be retrievable which allows for flexibility and for the long term maintenance of the system  2  in the well. 
     In a preferred embodiment, the system  2  may include packer  46  at the bottom of the production tubing  8  and make a straddle, which may be a system that has a seal on each end of assembly used to isolate an area on the outside between the two seals, in two runs by running the bottom packer  46  with a length of conduit  6  along with a sealing anchor latch  44 . Once the sealing anchor latch  44  is engaged and sealed into the seal bore in the top end of the bottom packer  46 , the upper packer  14  is set to provide the seal at the upper end section  22  of the wellbore  4 . The length between the sealing devices (i.e., packers  14  and  46 ) can be varied by running more (or less) conduit  6  on the lower end of the top packer  14 . 
     In some embodiments, the packer  14  or  46  might not be a dual seal bore packer and may be permanent, which may provide a lower cost alternative to the dual seal bore packer. For example, the bottom packer  46  may be permanently installed in the wellbore  4  because there might not be any need to retrieve the bottom packer  46  once set in the wellbore  4 . In some embodiments, an inflatable packer  14  or  46  may be used in the system  2 . 
     In some alternative embodiments, the upper or lower sealing mechanism may be provided by other devices, such as a pack-off. A pack-off is a sealing device set by compression from jar impact where an elastomer element is squeezed over a cone to engage the rubber to seal against the pipe wall of the tubing  8 . A pack-off may use a profile to land and lock the pack-off in place (e.g., via an anchor stop) to set upon in order to be able to jar (hammering down), expand, and compress the seal element. The sealing mechanism may also be provided by a patch, which may be a piece of pipe (conduit  6 ) that is installed by swedging the ends of the pipe outward to the end tubing  8  to create a mechanically anchored metal to metal seal at each end of the pipe (conduit  6 ). The length can be varied by adding additional length of pipe because the ends are the part of the pipe that are deformed to land in production tubing  8 . The sealing mechanism may also be provided by a liner that has an elastomeric seal on each end that may function similar to a patch, but with a compressed rubber seal on each end (and not swedging metal). In some embodiments, the upper sealing device may be placed in or on the wellhead  52  (instead of in the production tubing  8 ). 
     According to some aspects, the length of the conduit  6  may typically encompass substantially the entire depth of the production tubing  8  because of the likelihood of presence of multiple holes in the production tubing  8 . In some embodiment, the use of a gas lift requires the gas to enter the production stream at the lowest desired point, and if another hole exists in the tubing higher up, it would allow the gas to enter too high and leave a remaining taller height of water/oil in the tubing which would exert additional unwanted hydrostatic pressure from this fluid column and may reduce the ability of the well to flow. However, providing the disclosed control valve  34  may only require a sufficient length of conduit  6  or tool body length to provide a seal on both sides of the ACSV  34  to direct the annular pressure into the housing of the ACSV  34 . 
     In one embodiment, the straddle system run and set in the production tubing  8  includes (from the lower end  66  (in the bottom end section  26  of the wellbore  4 ) of the production tubing  8  on up to the upper end  68  (in the upper end section  22  of the wellbore  4 ) of the production tubing  8 ): 
     1. Bottom packer  46 , such as with dual seal bore; 
     2. Sealing anchor latch  44 ; 
     3. Lower hang-off sub assembly  42 , such as with a gas lift port/mandrel; 
     4. A first length of conduit  6 ; 
     5. Upper anchor hanger assembly  40 , such as with dual seal bore; 
     6. Sealing anchor latch  38 ; 
     7. Upper stiff pup joint  36 ; 
     8. Annular pressure control valve  34 , such as with an integral shear joint; 
     9. A second length of conduit  6 ; and 
     10. A top packer  14   
     According to some aspects, the annular pressure control valve  34  of the present disclosure is similar in design to current hydraulic control line SSCSV  60  widely used in oil well applications, but a hydraulic control line is not used with the disclosed annular pressure control valve  34 . 
     The metal conduit  6  may be surrounded by the production tubing  8 , and the production tubing  8  may be surrounded by a production casing  10 . An annular pressure is exerted in an annular area  12  between the production casing  10  and the production tubing  8 . The first top packer  14  may be coupled to a top portion  16  of the conduit  6 . 
     The annular pressure control valve  34  may be coupled to the metal conduit  6  below one or more pressure inlet ports  28  formed in the production tubing  8  below the first top packer  14 . The one or more pressure inlet ports  28  may extend between the annular area  12  (between the production casing  10  and the production tubing  8 ) and the outer surface  30  of the metal conduit  6  (e.g., through the production tubing  8 ). The one or more pressure inlet ports  28  may be situated below the first top packer  14  relative to the metal conduit  6 . 
     The annular pressure control valve  34  may be configurable in an open position ( FIG. 3 ) and in a closed position ( FIG. 4 ). The annular pressure control valve  34  may transition from the closed position ( FIG. 4 ) to the open position ( FIG. 3 ) responsive to the annular pressure (i.e., provided by the one or more pressure inlet ports  28 ) being equal to or above a threshold value. The annular pressure control valve  34  may transition from the open position ( FIG. 3 ) to the closed position ( FIG. 4 ) responsive to the annular pressure being less than the threshold value. 
     In some cases, the threshold value may be based on the setting depth associated the completion. For example, the threshold value may be greater than the hydrostatic pressure of sea water present at a setting depth, such as set at about two times the hydrostatic pressure of sea water present at a setting depth. This may allow for the control valve  34  to remain shut in following a catastrophic emergency and/or damage to a component, such as the wellhead  52  and/or platform being swept away by a storm. 
     In some embodiments, a flapper valve is used as the sealing mechanism in the valve  34 . For example, the flapper valve  34  may include an elongated arm that may attach at a hinge point or fulcrum point at one side of the conduit  6  or tubing  8 . The flapper valve  34  may include a spring element. The elongated arm may pivot about the hinge/fulcrum point to open and/or close the valve  34  (i.e., responsive to the annular pressure). For example, the annular pressure may cause the valve to mechanically open and/or close. The flapper value  34  may function as an interior shut-off valve. A flapper valve  34  may allow for a more open flow area (as compared to other types of valves). The annular pressure may act upon an unbalanced piston  70  (disposed in the tubing  8 ) causing it to move in response to the pressure differential ( FIG. 3 ). For example, a tubular-shaped piston  70  may pass through the flapper valve  34  to open it and then serve as a protective sleeve through which the subsequent production (oil) passes. This may act to prevent the production from flowing directly open the sealing component(s) of the flapper valve  34 . When the production stops, the annular pressure may drop, and a spring element may return the piston  70  to the original position ( FIG. 4 ), allowing the flapper valve to close and seal. The amount of pressure required to move the piston  70  may be based on the piston area and the spring rate. 
     In some embodiments, a ball valve may be used as the sealing mechanism in the valve  34 . For example, a ball valve  34  may have a spherical shaped piece (ball) positioned between an outer sealing assembly having an opening for the spherical shaped piece (ball). The ball may have an opening formed through the ball and may rotate to expose the opening to the inner opening of the conduit  6  (“opened position”) and may rotate to expose the non-opened portion of the ball to the inner opening of the conduit  6  (“closed position”). 
     In some embodiments, a sleeve valve may be used as the sealing mechanism in the valve  34 . In some embodiments, a poppet valve may be used as the sealing mechanism in the valve  34 . For example, a poppet may be a rubber coated spring-loaded valve that may open or close in response to the presence of absence of pressure action upon the seal area. 
     The pressure ports  28  are situated in the upper portion of the system  2  and allow the pressure surrounding the system  2  to be used to operate the valve  34  at whatever position the valve  34  is placed in the wellbore  4 . 
     The pressure control valve  34  of the present disclosure may be run in the closed position and opened by application of the pressure in the annulus  12  between the production tubing  8  and the casing  10 . The control of the valve  34  may be passively operated when pressure is supplied by a gas injected into the annulus  12  for gas lift through a gas lift mandrel (e.g., included in or attached to the hang-off sub assembly  56 ) installed in the production tubing. In some embodiments, if no gas lift mandrel is installed, a hole can be added in the tubing  8  above the SSCSV  60  that may be isolated by an upper straddle segment. 
     In some embodiments, the pressure from a hydraulic control line associated with the SSCSV  60  (which may be already present in the wellbore  4 ) may be used to provide the pressure to operate the control valve  34 . For example, if the exiting SSCSV  60  is rendered unusable or useless (e.g., via corrosion, flow cutting, hole in tubing  8 , etc.), a top seal and a bottom seal (as described herein) may be put on either sides of the existing SSCSV  60  and the control valve  34  placed in the tubing  8  between those two seals may operate to provide a safety valve. 
     In some embodiments, the control valve  34  of the present disclosure may include a shear mechanism to allow the a portion of the tubing  8  in the upper section  22  of the wellbore  4  to be pulled off, while leaving the control valve  34  functionally intact to maintain well control. 
     The inclusion of the control valve  34  in the liner/patch/straddle system  2  installation may be configured in such a manner that the annular pressure is accessible to the control valve  34 . In normal straddle applications, the ends  66  and  68  of the tubing  8  are sealed via elastomeric pack-off or metal-to-metal seal “elements.” However, having a seal on the straddle below the location of the control valve  34  would prevent the annular pressure from reaching the control valve  34 . To allow the annular pressure to reach the control valve  34 , the present disclosure may use and include an anchor/hanger assembly  40  or a packer  14  without a packing element at the upper end  22  that suspends the weight of the liner string system  2 , but still allows the annular pressure to make its way to the control valve  34 . This makes the operation of the control valve  34  passive and automatic with the presence or absence of annular pressure. 
     The present disclosure has an upper packer set  14 , where the control valve  34  is installed below and latched into the anchor/hanger assembly  40  to complete the upper end seal (to complete the production flow path to the wellhead  52 ). This allows the annular pressure to reach the control valve  34 . In the event of catastrophic wellhead  52  removal, such as a storm, the wellhead  52  may be pulled off and the production tubing  8  may be pulled and/or part at some point in the well. The upper straddle segment may be released from the upper end of the control valve  34  and the control valve  34  would remain for well control. 
     In an alternative embodiment, the system  2  can also be run as one continuous straddle with the control valve  34  in place below the upper sealing packer  14 . 
     The straddle system further incorporates a latching profile (e.g., sealing latch  38  and/or  44 ) for a drop/pump down sealing dart below. 
     Running the control valve  34  in conjunction with the straddle system is necessary to allow for full well control during a well failure event. This application gives the operator control of the well when the annular pressure in excess of the control valve cracking pressure is removed. The control valve  34  may be spring loaded, and may be capable of multiple opening/closing cycles (i.e., open at &gt;=300 psi, close at &lt;300 psi). The terms “about,” “approximately,” and “substantially” as used herein will be understood by persons of ordinary skill in the art and will vary to some extent on the context in which they are used. If there are uses of the term which are not clear to persons of ordinary skill in the art given the context in which it is used, “about” and “approximately” will mean +/−10% of the particular term and “substantially” will mean +/−15% of the particular term. 
     While preferred embodiments of the disclosure have been described, it is to be understood that the embodiments described are illustrative only and that the scope of the disclosure is to be defined solely by the appended claims when accorded a full range of equivalence, many variations and modifications naturally occurring to those skilled in the art from a perusal hereof.