METHOD

CROSS REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of and priority to co-pending U.S. Provisional Patent Application No. 63/019,689, filed on May 4, 2020, and entitled “Latch Back Pressure Valve System and Method,” the disclosure of which is hereby incorporated by reference herein in its entirety.

FIELD

[0002] This disclosure relates in general to extraction of oil and natural gas from a wellbore, and more specifically to a system and method employing a back pressure valve with a latching engagment.

BACKGROUND

[0003] In oilfield applications, it is common to use pumps, valves, seals, and the like to extract oil and natural gas from a well bore. Certain components of a wellhead assembly are subjected to a running procedure. In performing the running procedure, certain elements of the wellhead system should be confirmed to not have back pressure. Conventional components and conventional running procedures may not easily confirm that the bore hole is free of back pressure.

[0004] In conventional wellheads, a back pressure valve without latches is installed directly to the casing hanger. The back pressure valve is threaded to engage with internal threads on the casing hanger. However, in certain liner operations, a drill bit may damage the internal threads on the casing hanger, which may prevent subsequent engagement of the back pressure valve unless the casing hanger is replaced. Casing hangers are difficult and time- consuming to replace, particularly if the threads have been damaged by a drilling operation. Also, with the threaded engagement of the back pressure valve with the casing, the seal between the back pressure valve and the casing hanger cannot be tested.

[0005] U.S. Patent No. 9,297,226 to Nguyen et al. and assigned to Cameron International Corporation, which is incorporated by reference herein, discloses a back pressure valve installed directly to a casing hanger in a wellhead where the back pressure valve is installed in the wellhead using only axial forces and no rotation of a tool is employed to run, seat or lock the back pressure valve.

SUMMARY

[0006] This disclosure presents a latch back pressure valve for use with a wellhead assembly. The latch back pressure valve includes a body and at least one seal extending circumferentially around the body. A plurality of extendable latches are supported by the body and configured to engage with corresponding locking grooves. A poppet is configured to be displaced to open a passageway through the body. A hold-down ring is configured to engage a running tool such that rotation of the running tool causes the plurality of extendable latches to an extended position.

[0007] According to an embodiment, a method of sealing a wellhead includes the steps of securing a primary seal to a casing hanger, where the primary seal includes at least one locking groove configured to receive a latch of a latch back pressure valve. A wear bushing is secured to the primary seal to cover the at least one locking groove. The latch back pressure valve is landed on a load shoulder of the primary seal. A portion of the latch back pressure valve is rotated to extend a plurality of latches, where the extended latches are received by the at least one locking groove.

[0008] Other aspects, features, and advantages will become apparent from the following detailed description when taken in conjunction with the accompanying drawings, which are a part of this disclosure and which illustrate, by way of example, principles of the inventions hereof.

DESCRIPTION OF THU FIGURES

[0009] The accompanying drawings facilitate an understanding of the various embodiments.

[0010] FIG. 1 is perspective view of a wellhead including a latch back pressure valve according to the teachings of the present disclosure.

[0011] FIG. 2 is a cross section view of a casing hanger in the wellhead shown in FIG. 1. [0012] FIG. 3 is a cross section view of the installation of a primary seal in the wellhead shown in FIG. 1.

[0013] FIG. 4 is a cross section detail view of the primary seal shown in FIG. 3.

[0014] FIG. 5 is a cross section view of the installation of a test plug in the primary seal in the wellhead.

[0015] FIG. 6 is a cross section view of the installation of a wear bushing in the primary seal.

[0016] FIG. 7 is a cross section view of a washout tool received by the primary seal.

[0017] FIG. 8 is a perspective view of an embodiment of a latch back pressure valve according to the teachings of the present disclosure.

[0018] FIG. 9 is a cross section view of the latch back pressure valve shown in FIG. 8 with the latches in a retracted position.

[0019] FIG. 10 is a perspective view of a running tool used to secure the latch back pressure valve to the primary seal.

[0020] FIG. 11 is a cross section view of the latch back pressure valve made up with a running tool in position to be secured to the primary seal according to the teachings of the present disclosure.

[0021] FIG. 12 is a cross section of a wellhead showing the latch back pressure valve set within a primary seal according to the teachings of the present disclosure.

[0022] FIG. 13 is a cross section view of a wellhead with the latch back pressure valve secured within a primary seal and including a tubing spool.

[0023] FIG. 14 is a perspective view of a pressure release tool used with the latch back pressure valve according to the teachings of the present disclosure.

[0024] FIG. 15 is a cross section view of the pressure release tool of FIG. 14 used to open the latch back pressure valve. [0025] FIG. 16 is a cross section view of the latch back pressure valve being operated by the running tool to allow removal of the latch back pressure valve from the wellhead.

[0026] FIGS. 17A and 17B are detailed views showing the retraction of a latch of the latch back pressure valve shown in FIG. 16.

[0027] FIG. 18 is a cross section of an alternate embodiment of a latch back pressure valve and a primary seal that facilitates testing of the seal formed between the latch back pressure valve and an inner sealing surface of the primary seal.

[0028] Like numerals refer to like elements.

DETAILED DESCRIPTION

[0029] Mineral extraction systems are employed to extract various minerals and natural resources, including hydrocarbons from (e.g., oil and/or natural gas), or to inject substances into, the earth. In some embodiments, the mineral extraction system is land-based (i.e., a surface system) or subsea (i.e., a subsea system). The mineral extraction system allows a subterranean mineral deposit to be accessed through a wellbore. As shown in the FIGS., a wellhead 12 is positioned at the termination of the wellbore, and it accommodates various components associated with extracting the minerals.

[0030] According to embodiments of the present disclosure, the wellhead 12 includes a back pressure valve that is latched directly to a primary seal. The latches of the latch back pressure valve extend to be received by locking grooves formed in an interior surface of the primary seal. The primary seal is more easily removable from the wellhead than a casing hanger. For example, if the profile of the primary seal is damaged, the primary seal may still be easily removed from the wellhead. However, according to the teachings of the present disclosure, the features of the primary seal that engage with the latch back pressure valve are less likely than threads to be damaged such that they cannot engage with the latch back pressure valve. Unlike the threads that engage conventional back pressure valves, the locking grooves are more robust and may still function to engage the latch of the latch back pressure valve if it sustains minor damage. Moreover, the locking grooves of the primary seal may be protected by a wear bushing when a drill bit is run through for certain operations, for example drilling associated with a production liner. [0031] Use of the wear bushing is facilitated because the inner diameter of the primary seal is enlarged from the inner diameter that is necessary to accommodate a threaded back pressure valve. The enlarged inner diameter of the primary seal accommodates the wear bushing and still provides space to receive a drill bit, for example a drill bit used in connection with a production liner. The enlarged inner diameter of the primary seal accommodates the latching features of the latch back pressure valve as described in more detail below.

[0032] Thus, the latch back pressure valve may be more reliably installed and retrieved from the wellhead than a conventional back pressure valve that is threaded directly to a casing hanger or other component. As discussed above, engagement of the back pressure valve is not dependent on the integrity of the internal threads of a casing hanger, which are susceptible to damage during a drilling operation. Additionally, the latch back pressure valve can be tested to confirm that there is no back pressure acting on the wellhead before the latch back pressure valve is removed from the primary seal and removed from the wellhead.

[0033] According to an alternate embodiment, an external pressure source may be used to confirm the integrity of the seal formed between the latch back pressure valve and the primary seal. Thus, an operator can confirm proper seal of the latch back pressure valve and incidents of unintended ejection of the latch back pressure valve can be reduced or eliminated.

[0034] FIG. 1 is a perspective view of a wellhead 12 according to the teachings of the present disclosure. The wellhead 12 may be a Unitzed Lock Ring (ULR) Wellhead or an S- 29 Lock Ring Wellhead, both of which are available from SPM Oil & Gas, A Caterpillar Company, of Fort Worth, Texas. The wellhead 12 illustrated is a ULR wellhead. The wellhead 12 includes a baseplate assembly 14 and a casing head assembly 16. A quick connect blow out preventer (“BOP”) adapter 18 is secured to the top portion of the casing head assembly 16. The BOP adapter 18 supports a blowout preventer 25 (see FIG. 2) or a tubing head 60 (see FIG. 13). As discussed in further detail below, the wellhead 12 supports a primary seal 42. A back pressure valve 52 is latched to the primary seal 42 according to the teachings of the present disclosure.

[0035] FIG. 2 is a cross-section of the wellhead 12 showing a stage of a wellbore operation, such as the installation of the casing hanger 26 that supports a smaller diameter casing 20, for example casing having a 7 inch inner diameter. The baseplate assembly 14 is disposed over a conductor pipe (not shown), which may also be referred to as a 20 inch casing. A smaller diameter casing 22 extends through the conductor pipe, for example a casing having a diameter of 13 and 3/8 inches extends through the conductor pipe. The casing 24 is supported by a lower casing hanger 41. The casing 24 and the casing hanger 41 may have a diameter of 9 and 5/8 inches. The lower casing hanger 41 is supported by the casing head assembly 16.

[0036] A lower seal assembly 43 is supported by the lower casing hanger 41. The lower seal assembly 43 provides the transition from the casing hanger 41 supporting the casing 24 to the casing hanger 26 supporting the casing 20.

[0037] The wellhead 12 typically includes multiple components that control and regulate activities and conditions associated with the well. For example, the wellhead 12 generally includes bodies, valves and seals that route produced minerals, provide for regulating pressure in the well, and provide for the injection of chemicals into the well bore (down hole). In certain embodiments, the wellhead 12 includes what is colloquially referred to as a Christmas tree. The mineral extraction system may include other devices that are coupled to the wellhead 12, and devices that are used to assemble and control various components of the wellhead 12. A blowout preventer (“BOP”) 25 is secured to the wellhead 12.

[0038] One or more tools may be suspended from a drill string. In certain embodiments, the tool includes a running tool that is lowered (i.e., run) from an offshore vessel to the well and/or the wellhead 12. In other embodiments, such as surface systems, the running tool may be positioned over and/or lowered into the wellhead 12 via a crane or other supporting device. The Christmas tree generally includes a variety of flow paths (i.e., bores), valves, fittings, and controls for operating the well.

[0039] The wellbore may contain elevated pressures. For example, the well bore may include pressures that exceed 15,000 pounds per square inch (PSI). Accordingly, mineral extraction systems employ various mechanisms, such as seals, plugs and valves, to control and regulate the well.

[0040] At least one casing hanger (i.e., tubing hanger or casing hanger) is typically disposed within the wellhead 12 to secure tubing and casing suspended in the well bore, and to provide a path for hydraulic control fluid, chemical injections, drill string, production liner, and the like.

[0041] According to an embodiment, the casing hanger 26 is approximately seven inches in inner diameter, for example 6.4 inches in inner diameter. A torque tool assembly 40 is fitted around the casing hanger 26. The torque tool 40 is lowered into the wellhead 12. The torque tool 40 is rotated clockwise 7-8 turns to a positive stop. After the positive stop, the torque tool 40 is rotated counter clockwise until a sleeve is aligned with flute slots on the casing hanger 26. Two socket head cap screws on the sleeve are removed, and the sleeve is lowered inside the flute slots of the casing hanger 26. The casing hanger 26 is lowered until it lands on a load shoulder of the lower seal assembly 43. The torque tool 40 is rotated counter clockwise 7-8 turns and picked up vertically to remove the torque tool 40 from the wellhead 12. The casing hanger 26 may be cemented in the wellhead 12.

[0042] FIG. 3 is a cross-section of the wellhead 12 illustrating installation of the primary seal 42 using a running tool 44; FIG. 4 is a detail view of the primary seal 42 attached to the lower seal assembly 43. After installing the casing hanger 26, the primary seal 42 is installed in the wellhead 12. The primary seal 42 provides a transition from the casing hanger 26 supporting the casing 20 to the production tubing/liner (not shown). The primary seal 42 surrounds the casing hanger 26 and secures to the lower seal assembly 43.

[0043] According to an embodiment, the running tool 44 is assembled with the primary seal 42, and they are lowered into the blowout preventer 25. The primary seal 42 is lowered to contact a dummy hanger or other suitable landing surface. Continued downward force exerted on the primary seal 42 by the running tool 44 is opposed by the dummy hanger or other suitable landing surface. This opposed downward force downwardly displaces an energizing ring 30, which radially displaces a lock ring 32. Displacement of the lock ring 32 results when the inward radial bias in the lock ring is opposed by the energizing ring 30. The expanded lock ring 32 is received in a groove 34 formed in the secondary /lower seal 43. According to an embodiment, approximately 30,000 pounds of force will deploy the lock ring 32 to be received by the groove 34.

[0044] The primary seal 42 includes an elastomeric annular seal 36 that contacts an external surface of the casing hanger 26 and an internal surface of the primary seal 42. Thus, the primary seal 42 forms a seal in the wellhead and is constrained from vertical movement by engagement of the lock ring 32 with the groove 34. The seals on the primary seal 42 are tested, and then the pressure is released using a pressure release tool. As discussed in further detail below, the primary seal 42 includes locking grooves 38 that receive the latches 54 that are deployed to extend from the back pressure valve 52. According to an embodiment, a washout tool may be used prior to installation of the primary seal 42.

[0045] FIG. 5 illustrates the installation of a test plug 46 to test the blowout preventer 25. The test plug 46 is lowered into the wellhead 12 until it lands on a shoulder of the primary seal 42. The blowout preventer 25 is tested, and the pressure is relieved. The test plug 46 is then removed.

[0046] FIG. 6 illustrates installation of the wear bushing 48 in the wellhead 12. The wear bushing 48 may also be referred to as a drilling protector bushing. The wear bushing 48 includes a cylindrical wall 39 that is received by the primary seal 42 and protects the internal features of the primary seal 42 during drilling operations. According to certain embodiments, the wear bushing 48 protects features such as the locking grooves 38 that engage with the latch back pressure valve 52 from damage that might otherwise occur, if exposed and contacted by a drill bit or the drill string during drilling operations.

[0047] A test plug/retrieving tool and wear bushing 48 are lowered though the blowout preventer stack 25 and landed on a load shoulder of the primary seal 42. The wear bushing 48 is released from the test plug/retrieving tool by rotating the drill pipe counter-clockwise approximately 90° and lifting the drill pipe. The wear bushing 48 covers the locking grooves 38 on the primary seal 42 that engage with the latch back pressure valve 52. A drill bit and drill string can be run through the wear bushing 48 and drift of the drill string or any debris generated will not damage locking grooves of the primary seal 42 because they are covered and protected by the wear bushing 48. As discussed above, use of the wear bushing 48 in the running procedure is enabled because the inner diameter of the primary seal 42 is enlarged, but the primary seal 42 still engages with the latch back pressure valve 52. A conventional threaded back pressure valve would not engage with the enlarged inner diameter of a primary seal. According to certain embodiments, the inner radius of the primary seal 42 with the installed wear bushing 48 is sized to accommodate a 6 and 1/8 inch drill bit. In this manner, drilling engineers may drill deeper and more efficiently, which may result in improved well design, lower cost, and higher performance. [0048] The wear bushing 48 is removed when access to the locking groves 38 of the primary seal 42 is needed. The wear bushing 48 can be removed by lowering the test plug/retrieving tool through the blowout preventer 25 and landing it on the wear bushing 48. The test plug/retrieving tool is rotated into the wear bushing 48 by rotating the drill pipe clockwise until the tool drops into place. The tool is rotated approximately 90° to lock the tool into the wear bushing 48. The drill pipe is lifted to retrieve the wear bushing 48.

[0049] FIG. 7 shows a washout tool 50 positioned in the wellhead 12. The washout tool 50 includes a centralizer 51. The washout tool 50 is used to clean the primary seal 42. For example, the washout tool 50 is used to clean the locking grooves 38 of the primary seal 42 to which the latch back pressure valve 52 is secured. The washout tool 50 also cleans the internal sealing surface 45 of the primary seal 42 (see FIG. 4) and washes away any debris that might have been generated by the drilling operation. The washout tool 50 prepares the primary seal 42 for installation of the latch back pressure valve 52.

[0050] FIG. 8 shows a perspective view of the latch back pressure valve 52. The latch back pressure valve 52 may be a seven inch latch back pressure valve 52, type L, one-way check valve, with a seven inch nominal dimension. The latch back pressure valve 52 includes a body 53, a top cap 58, and a plurality of latches 54. The latch back pressure valve 52 also includes a spring seal 66, which may form a better seal with the primary seal 42 than a conventional compression seal of a threaded back pressure valve because it does not require compression to create a seal. According to certain embodiments, the spring seal 66 (also referred to as an S-Seal) is a self-energizing interference seal. At least a portion of the S-seal 66 is formed of an elastomeric material, which may include a spring molded into or otherwise embedded in the elastomeric material. A bottom portion 55 of the latch back pressure valve 52 includes openings 57 that allow an operator to view a plunger 59 and a spring 61 associated with a poppet valve to ensure proper operation before installing the latch back pressure valve 52 in the wellhead 12.

[0051] The latch back pressure valve 52 also includes at least one anti-rotation pin 68 extending from the body 53. According to certain embodiments, the anti-rotation pin 68 is spring loaded. In one embodiment, a first anti-rotation pin 68 extends from the body 53 and a second anti-rotation pin 68 (not shown) is disposed 180° opposite the first anti-rotation pin 68. Each of the anti-rotation pins 68 is received in a corresponding axial slot 63 disposed at a top portion of the primary seal 42 (see FIG. 4). The anti-rotation pins 68 may be spring loaded such that the primary seal 42 causes them to retract until they are aligned with the axial slot 63. Engagement of the axial slots 63 with the anti-rotation pins 68 restricts rotation of the body, such that rotating the running tool rotates a hold-down ring to deploy the latches 54, instead of rotating the body 53 of the latch back pressure valve 52 (see FIG. 9).

[0052] FIG. 9 is a cross-section of a side-elevation view of the latch back pressure valve 52. The latch back pressure valve 52 includes a hold-down ring 64 that is threaded to an internal thread 65 of the body 53 such that rotation of the hold-down ring 64 displaces the hold-down ring 64 axially. According to certain embodiments, counterclockwise rotation of the hold-down ring 64 displaces the hold-down ring 64 axially downward. The hold-down ring 64 includes at least one slot 74 that engages with a portion of a running tool to allow the hold-down ring 64 to be rotated to deploy the latches 54. According to an embodiment, the slot 74 has a “J” profile and may be referred to as a J-slot. The hold-down ring 64 may include two J-slots 74 disposed 180° circumferentially apart from each other (only one J-slot shown).

[0053] With continuing reference to FIG. 8 together with FIG. 9, in an embodiment, the latch back pressure valve 52 includes four extendable latches 54. Each latch 54 is a generally cube-shaped body that is received in a corresponding opening 67 in the body 53 of the latch back pressure valve 52. Alternate embodiments may include two, three, or more latches. According to one embodiment, four latches are disposed equidistant circumferentially about the body 53. Each opening 67 constrains the latch 54 to a generally radial displacement. According to an embodiment, a lower surface 69 is slanted to add a slight upward axial component to the displacement of each latch 54. Each latch 54 includes a first peak 71 separated by from a second peak 73 by a valley 75. The peaks 71, 73 are received in corresponding spaced apart grooves 38 formed in an inner surface of the primary seal 42 (see Fig. 4). The valley 75 receives a portion of the primary seal 42. In addition, an axial flange 77 is disposed at a rear of each latch 54. The axial flange 77 engages a corresponding portion of the body 53 such that the flange 77 is captured between the hold-down ring 64 and the body 53, which constrains the displacement of each latch 54.

[0054] FIG. 10 is a perspective view of a running tool 70 used by an operator to deploy the latches 54 and secure the latch back pressure valve 52 in the primary seal 42. The running tool 70 includes an engagement pin 72 that engages with the J-slot 74 on the hold-down ring 64. The J-slots 74 engage with the pin 72 of the running tool 70 to allow the running tool 70 to rotate the hold-down ring 64 to deploy the latches 54.

[0055] To install the latch back pressure valve 52, the hold-down ring 64 is initially positioned at its upper most position in contact with the top cap 58. The running tool 70 is made up with the back pressure valve 52 by inserting the running tool 70 into the hold-down ring 64 and rotating the running tool 70 clockwise approximately a quarter turn such that the running tool 70 engages with the hold-down ring 64. With the running tool 70 engaged with the hold-down ring 64, the operator may manually rotate the running tool 70 to ensure that the hold-down ring 64 is properly displaced and the latches 54 properly deploy. The running tool 70 is turned clockwise to ensure the hold-down ring 64 is returned to the install position and in contact with the top cap 58. After ensuring proper operation of the latch back pressure valve 52, the running tool 70 is inserted into a socket end of a polished rod and a pin is positioned to secure the running tool 70 in the polished rod. In certain embodiments, prior to lowering the polished rod (also referred to as a dry rod), the wellhead 12 is checked to determine that there is no pressure in the wellhead 12.

[0056] FIG. 11 is a cross-section view of the latch back pressure valve 52 engaged with the running tool 70 with the latch back pressure valve 52 in position to be latched to the primary seal 42. The polished rod (not shown) together with the running tool 70 and the latch back pressure valve 52 are lowered through the blow out preventer 25 and into the wellhead 12. The latch back pressure valve 52 lands on a load shoulder 79 of the primary seal 42, which results in a positive stop. The operator may take measurements to ensure that the latch back pressure valve 52 is properly positioned within the primary seal 42.

[0057] With the latch back pressure valve 52 disposed in the primary seal 42 in position to be secured to the primary seal 42, the latches 54 may be extended by the operator. The operator manipulates the running tool 70 to drive the hold-down ring 64 axially downward. For example, the operator may rotate the running tool 70, which rotates the hold-down ring 64, about seven turns counter-clockwise. Engagement of the threads of the hold-down ring 64 with corresponding threads 65 of the body 53 of the latch back pressure valve 52 directs the hold-down ring 64 axially downward.

[0058] Returning to FIG. 9, the hold-down ring 64 is sized and shaped to radially displace each of the latches 54 as it is displaced downward. Specifically, the hold-down ring 64 includes a nominal diameter body 78 and a tapered portion 81 that tapers to a smaller diameter. The tapered portion 81 acts on a rear surface of each latch to direct it radially outward. Maximum displacement of the latches 54 is achieved when the nominal diameter body 78 of the body engages the rear surfaces of the latches 54. The hold-down ring 64 contacts an upward facing surface 83 of the body 53 of the latch back pressure valve 52 and positively stops the downward motion of the hold-down ring 64. According to an embodiment, the running tool 70 opens a poppet valve 76 as the hold-down ring 64 is directed downward.

[0059] FIG. 12 is a cross section of the wellhead 12 showing the latch back pressure valve 52 engaged with the primary seal 42. The latch back pressure valve 52 is engaged with the primary seal 42 by rotating the dry rod counterclockwise. The counterclockwise rotation causes the plurality of latches 54 to extend from the body 53 of the latch back pressure valve 52. The latches are extended and received in a corresponding locking grooves 38 formed in an inner surface of the primary seal 42. The engagement of the latches 54 with the locking grooves in the primary seal sets the latch back pressure valve 52. After setting the latch back pressure about 52 the dry rod may be picked up vertically to remove the dry rod from the wellbore.

[0060] If an operator encounters difficulty in installing the latch back pressure valve 52, the primary seal 42 may be removed from the wellhead 12. The disclosed intended engagement of the latch back pressure valve 52 with the primary seal 42 may offer significant advantages in the event the latch back pressure valve 52 is not properly latched and/or sealed with the primary seal 42. To address the problem, an operator does not have to cut out a casing hanger to retrieve the latch back pressure valve 52, as he would to retrieve a conventional back pressure valve. The latch back pressure valve 52 may be removed either by disengaging the latches 54 and removing the latch back pressure valve with a dry rod or a hydraulic lubricator. Alternatively, the latch back pressure valve 52 may be retrieved by removing the primary seal 42 and the latch back pressure valve 52 together. This offers a significant improvement over removing a damaged casing hanger.

[0061] FIG. 13 is a cross section of the wellhead 12 showing a tubing head body 60 installed at the wellhead 12 with the latch back pressure valve 52 installed in the primary seal 42. The latch back pressure valve 52 prevents pressure from escaping the wellbore when the blow out preventer 25 is removed to allow the tubing head 60 to be installed. According to embodiments, the tubing head 60 supports tubing or a liner having an inner diameter of approximately 4.5 inches.

[0062] FIG. 14 is a perspective view of a pressure testing/pressure release tool 80 used according to the teachings of the present disclosure. The pressure release tool 80 includes a threaded portion 82. The threaded portion 82 is sized and shaped to engage with corresponding internal threads 84 of the cap 58. The pressure release tool 80 also includes a rod portion 86 that extends below the threaded portion 82. The rod portion 86 is configured to open the poppet valve of the latch back pressure valve 52.

[0063] FIG. 15 is a cross-section of the wellhead 12 with the latch back pressure valve 52 secured to the primary seal 42 and the tubing head 60 (and the blow out preventer 25) removed. The pressure release tool 80 is shown actuating poppet valve of the latch back pressure valve 52. The threaded portion 82 of the pressure testing/release tool 80 engages the interior thread 84 on the top cap 58. Rotating the pressure release tool 80 drives the pressure release tool 80 axially downward. The rod portion 86 forces the poppet 76 axially downward and breaks a seal with the valve body.

[0064] Once the pressure testing tool 80 actuates the poppet 76, if present, a back pressure in the wellbore will be delivered through the interior of the latch back pressure valve 52. The operator can observe this pressure by looking for water levels to rise or sustained bubbles. If no rising water levels or sustained bubbles are observed, the operator can retrieve the latch back pressure valve 52 with the dry rod. If pressure is observed, and the tubing head has already been removed, the tubing head may be reinstalled and the latch back pressure valve 52 may be retrieved with a hydraulic lubricator. In this manner, the latch back pressure valve 52 can be used to test to determine if a possibly dangerous back pressure is present in the wellbore. Advantageously, the opening of the poppet valve 76 is performed with a separate pressure testing/pressure release tool 80 than the running/retrieval tool 70. Also, the separate pressure testing/pressure release tool 80 is lowered into the wellbore separately from the running/retrieval tool 70. In this manner, a wellbore back pressure may be tested while the latch back pressure valve 52 is secured to the primary seal 42 and prior to initiating a procedure to remove the latch back pressure valve 52 from the wellhead 12.

[0065] FIG. 16 is a cross section of the latch back pressure valve 52 being disengaged from the primary seal 42. The running tool 70 is used to retrieve the latch back pressure valve 52. The running tool 70 is lowered on to the latch back pressure valve 52 and locked to the latch back pressure valve 52 by rotating the running tool clockwise 90° to engage the J- slot 74 of the hold-down ring 64. Lowering the running tool 70 and engaging the J-slot 74 will open the poppet valve 76, particularly if the pressure in the wellbore has already been equalized using the pressure relief tool 80, as discussed above with respect to FIG. 15. The running tool 70 is then rotated clockwise approximately eight turns until a positive stop is achieved. The positive stop occurs when the hold-down ring 64 contacts a bottom surface of the cap 58. This axially upward displacement of the hold-down ring 64 allows the latches 54 to retract and release from the locking grooves 38. The running tool 70 is secured to the latch back pressure valve 52, and the tool 70 and the valve 52 are lifted vertically to remove the latch back pressure valve 52 from the wellhead 12.

[0066] FIGS. 17A and 17B are detailed views showing the latch back pressure valve 52 being lifted from the wellhead 12. Angled surfaces 90 on the locking groves 38 interact with corresponding angled surfaces 92 on the latches 54. An upward force applied to the running tool 70 creates a radially inward force on the latches due to the interaction of the angled surfaces 90 of the locking grooves 38 on the angled surfaces 92 on the latches 54. According to certain embodiments, the angled surfaces 90 and the angled surfaces 92 are slanted approximately 45° with respect to vertical. According to an embodiment, the incline of the surface 69 of the body 53 of the latch back pressure valve 52 also facilitates retraction of the latches 54 caused by the upward force exerted on the latch back pressure valve 52. The latch back pressure valve 52 is sized to be retrieved through the tubing head 60.

[0067] FIG. 18 shows a cross section of the wellhead 12 with an alternate embodiment of a latch back pressure valve 152 according to the teachings of the present disclosure. The latch back pressure valve 152 shown in FIG. 18 includes the same features as the latch back pressure valve 52, but it additionally facilitates testing of the integrity of the seal formed between the valve 152 and the primary seal 142 to ensure that the latch back pressure valve 152 remains in place and sealed with the primary seal 142 if subjected to high pressures, such as those that might occur in a wellbore in connection with a liner operation.

[0068] A lower portion of a body 102 of the latch back pressure valve 152 is extended to accommodate at least two seals. According to an embodiment, an upper seal 104 is disposed vertically spaced apart from a lower seal 106. The seals 104, 106 are elastomeric seals extending around the full perimeter of the body 102. The seals 104, 106 may be spring seals or S-seals and may include the same spring embedded in elastomeric material as described above with respect to FIGS. 8 and 9. Thus, the seals 104, 106 may be self-energizing interference seals. The upper seal 104 is received in an upper channel 108 formed in the body 102, and the lower seal 106 is received in a lower channel 110 in the body 102 of the latch back pressure valve 152. The upper seal 104 and the lower seal 106 and the upper channel 108 and the lower channel 110 extend around the circumference of the body 102.

[0069] When the latch back pressure valve 152 is landed on the load shoulder of the primary seal 142, the spring seals 104, 106 are compressed and the resiliency of the seals 104, 106 forms seals between an inner seal surface 114 of the primary seal 142 and the upper seal 104 and the lower seal 106. This seal may be able to withstand high pressures in a range of 10,000 to 15,000 psi.

[0070] Advantageously, the seals formed by the upper seal 104 in the lower seal 106 may be tested to ensure that the latch back pressure valve 152 is properly seated and latched in the primary seal 142 such that the latch back pressure valve 152 can withstand high pressures without failing or the seals leaking, which under high pressures may result in unintended ejection of the latch back pressure valve 152 from the wellhead 12. The primary seal 142 includes an input conduit 116 and a gauge conduit 118. Each of the input conduit 116 and the gauge conduit 118 include a vertically extending portion 117, 119 running to an angled portion 121, 123 angled to extend through the wall of the primary seal 142 to the inner seal surface 114. Each of the angled portions 121, 123 may have an outlet at the exterior of the primary seal 142 that may be plugged with a permanent or removable plug.

[0071] An external pressure source (not shown) can be fluidly coupled to the input conduit 116, for example at the top of the input conduit 116. The input conduit 116 communicates a fluid, such as air or other gas, to a portion of the valve body 102 vertically disposed between the upper seal 104 and the lower seal 106. A gauge (not shown) can be fluidly coupled to the gauge conduit 118, for example at the top of the gauge conduit 118. The pressure in the input conduit 116 and the gauge conduit 118 may be increased by the external pressure source to as much as 15,000 psi.

[0072] According to certain embodiments, the latch back pressure valve 152 is landed and latched to the primary seal 142, and then the blowout preventer 120 is removed. With the blowout preventer removed 120, the input conduit 116 and the gauge conduit 118 are accessible to enable coupling of the external pressure source and the pressure gauge respectively.

[0073] The integrity of the seal formed between the upper seal 104 and the lower seal 106 and the sealing surface 114 of the primary seal 142 can be determined by the pressure gauge that is coupled to the gauge conduit 118. The gauge will detect a pressure drop if pressure leaks around either the upper seal 104 or the lower seal 106. The pressure drop indicates that a seal has not been properly made. If no pressure drop is measured, it can be safely determined that the latch back pressure valve 152 is properly landed and latched and can withstand high wellbore pressures that may be generated subsequently. After testing, the external pressure source may be decoupled and the pressure may be released from the input conduit 116 and the gauge conduit 118, such that the latch back pressure valve 152 is no longer subject to the external pressure.

[0074] The operator has confidence that the blowout preventer 120 can be safely removed without fear that the seal formed by the latch back pressure valve 152 will fail causing the latch back pressure valve 152 to be forcefully ejected by a back pressure in the wellbore that may be generated in connection with a liner operation. The back pressure in the wellbore may be tested using the pressure release tool 80, as described above with respect to FIG. 15. In this manner, the latch back pressure valve 152 provides a safer environment for oilfield workers to perform certain liner operations that require sealing the wellbore. If the seal test fails (i.e. the gauge shows a pressure drop), the operator can take corrective action to repair or replace the latch back pressure valve 152 and/or the primary seal 142.

[0075] The dual elastomeric seal facilitates the sealing test function by providing a space between seals that may be pressurized and leakage around either of the seals, either around the upper seal 104 upward or around the lower seal 106 downward toward the wellbore may be detected. Moreover, the dual seal provides additional sealing surface area, which may result in a more robust seal than a single seal embodiment. The seal may be tested whether or not the testing tool 80 or the running tool 70 is engaged with the latch back pressure valve 152.

[0076] In the foregoing description of certain embodiments, specific terminology has been resorted to for the sake of clarity. However, the disclosure is not intended to be limited to the specific terms so selected, and it is to be understood that each specific term includes other technical equivalents which operate in a similar manner to accomplish a similar technical purpose.

[0077] In the specification and claims, the word “comprising” is to be understood in its “open” sense, that is, in the sense of “including”, and thus not limited to its “closed” sense, that is the sense of “consisting only of’. A corresponding meaning is to be attributed to the corresponding words “comprise”, “comprised” and “comprises” where they appear.

[0078] In addition, the foregoing describes only some embodiments of the invention(s), and alterations, modifications, additions and/or changes can be made thereto without departing from the scope and spirit of the disclosed embodiments, the embodiments being illustrative and not restrictive.

[0079] Furthermore, invention(s) have described in connection with what are presently considered to be the most practical and preferred embodiments, it is to be understood that the invention is not to be limited to the disclosed embodiments, but on the contrary, is intended to cover various modifications and equivalent arrangements included within the spirit and scope of the invention(s), as defined solely by the appended claims. Also, the various embodiments described above may be implemented in conjunction with other embodiments, e.g., aspects of one embodiment may be combined with aspects of another embodiment to realize yet other embodiments. Further, each independent feature or component of any given assembly may constitute an additional embodiment.