WO2021077083A1

WO2021077083A1 - Sealing assembly

Info

Publication number: WO2021077083A1
Application number: PCT/US2020/056326
Authority: WO
Inventors: Nicolas ARTEAGA
Original assignee: Cameron International Corporation; Cameron Technologies Limited
Priority date: 2019-10-17
Filing date: 2020-10-19
Publication date: 2021-04-22

Abstract

A sealing assembly is configured to form a seal to separate a higher-pressure environment from a lower-pressure environment. The sealing assembly includes a first elastomeric member comprising a first tapered contacting surface and a second elastomeric member comprising a second tapered contacting surface. The first elastomeric member and the second elastomeric member are configured to form the seal as at least a first portion of the first tapered contacting surface and at least a second portion of the second tapered contacting surface are forced into contact with one another.

Description

SEALING ASSEMBLY

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 62/916,540, entitled “SEALING ASSEMBLY,” filed October 17, 2019, which is hereby incorporated by reference in its entirety for all purposes.

BACKGROUND

[0002] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.

[0003] A blowout preventer (BOP) is installed above a wellhead to seal and control an oil and gas well during various operations. For example, during drilling operations, a drill string may be suspended from a rig through the BOP into a wellbore. A drilling fluid is delivered through the drill string and returned up through an annulus between the drill string and a casing that lines the wellbore. In the event of a rapid invasion of formation fluid in the annulus, commonly known as a “kick,” the BOP may be actuated to seal the annulus and to control fluid pressure in the wellbore, thereby protecting well equipment positioned above the BOP.

BRIEF DESCRIPTION OF THE DRAWINGS

[0004] Various features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:

[0005] FIG. 1 is a schematic diagram illustrating a drilling system, in accordance with an embodiment of the present disclosure;

[0006] FIG. 2 is a cross-sectional top view of a portion of a blowout preventer (BOP) that may be used in the drilling system of FIG. 1 , in accordance with an embodiment of the present disclosure; [0007] FIG. 3 is a schematic view of a sealing assembly that may be used in the BOP of FIG. 2, wherein the sealing assembly is in an unsealed configuration, in accordance with an embodiment of the present disclosure;

[0008] FIG. 4 is a schematic view of the sealing assembly of FIG. 3, wherein the sealing assembly is in a contact configuration, in accordance with an embodiment of the present disclosure;

[0009] FIG. 5 is a schematic view of the sealing assembly of FIG. 3, wherein the sealing assembly is in a sealed configuration, in accordance with an embodiment of the present disclosure;

[0010] FIG. 6 is a side view of a sealing element that may be used in the sealing assembly of FIG. 3, wherein the sealing element includes a straight sealing edge, in accordance with an embodiment of the present disclosure;

[0011] FIG. 7 is a perspective view of the sealing element of FIG. 6, in accordance with an embodiment of the present disclosure;

[0012] FIG. 8 is a top view of the sealing element of FIG. 6, in accordance with an embodiment of the present disclosure;

[0013] FIG. 9 is a side view of a sealing element that may be used in the sealing assembly of FIG. 3, wherein the sealing element includes a curved sealing edge, in accordance with an embodiment of the present disclosure;

[0014] FIG. 10 is a perspective view of the sealing element of FIG. 9, in accordance with an embodiment of the present disclosure; and [0015] FIG. 11 is a top view of the sealing element of FIG. 9, in accordance with an embodiment of the present disclosure.

DETAILED DESCRIPTION

[0016] One or more specific embodiments of the present disclosure will be described below. These described embodiments are only exemplary of the present disclosure. Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers’ specific goals, such as compliance with system -related and business- related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0017] The present disclosure relates generally to a sealing assembly (e.g., packing assembly), as well as methods for using the sealing assembly. More specifically, the present disclosure relates to a sealing assembly that includes opposed sealing elements and that is configured for use in an environment in which an elastomer sealing material of the opposed sealing elements is subjected to forces to generate a sealing effect. For example, the sealing assembly may be configured for use in wellbore sealing equipment, such as in pressure containing equipment (e.g., blowout preventers [BOPs], such as pipe ram BOPs, blind ram BOPs, shear ram BOPs, and/or annular BOPs). As discussed in more detail below, the sealing assembly includes features (e.g., tapered contacting surfaces of the opposed sealing elements) that enable a reduction in an amount of force that is applied to the opposed sealing elements to generate the sealing effect. Thus, when the sealing assembly is used in the wellbore sealing equipment, the features may facilitate sealing of a wellbore while a wellbore pressure is below a wellbore-assist threshold.

[0018] In order to generate the sealing effect and to provide a fluid seal for a fluid, the elastomer sealing material of the opposed sealing elements has an internal pressure (e.g., between the tapered contacting surfaces) that is higher than a fluid pressure of the fluid. In some embodiments, an actuator assembly may drive the opposed sealing elements against one another to provide the internal pressure that is higher than the fluid pressure of the fluid. Furthermore, in some embodiments, the fluid may assist the actuator assembly (e.g., by providing an additional force) to drive the opposed sealing elements against one another to provide the internal pressure that is higher than the fluid pressure of the fluid. Such techniques may be particularly useful in BOPs during high pressure conditions, as the fluid at a high pressure within the wellbore may provide a sufficient amount of the additional force to effectively assist the actuator assembly to drive the opposed sealing elements against one another to provide the internal pressure that is higher than the fluid pressure of the fluid. Flowever, it is presently recognized that during low pressure conditions, the fluid at a low pressure within the wellbore may not provide the sufficient amount of the additional force and may not effectively assist the actuator assembly to drive the opposed sealing elements against one another to provide the internal pressure that is higher than the fluid pressure of the fluid. [0019] Accordingly, the sealing assembly disclosed herein includes the features that enable the sealing assembly to generate the sealing effect and to provide the fluid seal for the fluid with less force applied to the opposed sealing elements (e.g., as compared to existing sealing elements, such as existing sealing elements without the tapered contacting surfaces). In turn, this may enable the sealing assembly to generate the sealing effect and to provide the fluid seal for the fluid during low pressure conditions (e.g., to seal the wellbore while the wellbore pressure is below the wellbore-assist threshold, such as below 5, 4, 3, 2, or 1 Megapascals). However, it should be appreciated that the sealing assembly may be used in any of a variety of environments and/or conditions where it may be desirable to reduce the force applied to the opposed sealing elements to generate the sealing effect and to provide the fluid seal for the fluid.

[0020] Furthermore, while certain embodiments are described in the context of a drilling system and drilling operations to facilitate discussion, it should be appreciated that the sealing assembly may be adapted for use in other contexts and during other operations. For example, the sealing assembly may be used in a BOP (e.g., wireline valve) of a pressure control equipment (PCE) stack that is coupled to and/or positioned vertically above a wellhead during various intervention operations (e.g., inspection or service operations), such as wireline operations in which a tool supported on a wireline is lowered through the PCE stack to enable inspection and/or maintenance of a well. In the present disclosure, a conduit may be any of a variety of tubular or cylindrical structures, such as a drill string, a wireline, a Streamline™, a slickline, a coiled tubing, or other spoolable rod.

[0021] FIG. 1 is a schematic diagram of a drilling system 10, in accordance with an embodiment of the present disclosure. The drilling system 10 is an offshore drilling system that is configured to drill a wellbore 12. The drilling system 10 includes an offshore vessel or platform 14 at a sea surface 16 and a blowout preventer (BOP) stack assembly 18 mounted to a wellhead 20 at a sea floor 22. The platform 14 is equipped with a derrick 24 that supports a hoist, and a drilling riser 26 extends from the platform 14 to the BOP stack assembly 18. The drilling riser 26 is configured to return drilling fluid or mud to the platform 14 during drilling operations. One or more hydraulic conduits 28 may extend along an outside of the drilling riser 26 from the platform 14 to the BOP stack assembly 18. The one or more hydraulic conduits 28 supply a pressurized hydraulic fluid to the BOP stack assembly 18. A casing 30 may extend from the wellhead 20 into the wellbore 12. [0022] Downhole operations, such as drilling operations, are carried out by a conduit 32 (e.g., drill string) that is supported by the derrick 24 and that extends from the platform 14 through the drilling riser 26, through the BOP stack assembly 18, and into the wellbore 12. A downhole tool 34 may be coupled to a lower end of the conduit 32. In general, the downhole tool 34 may include any suitable downhole tools for drilling, completing, evaluating, and/or producing the wellbore 12 including, without limitation, drill bits, packers, cementing tools, casing or tubing running tools, testing equipment and/or perforating guns. During the downhole operations, the conduit 32, and hence the downhole tool 34 coupled thereto, may move axially, radially, and/or rotationally relative to the drilling riser 26 and the BOP stack assembly 18.

[0023] The BOP stack assembly 18 is mounted to the wellhead 20 and is designed and configured to control and seal the wellbore 12, thereby containing hydrocarbon fluids (liquids and gases) therein. In this example, the BOP stack assembly 18 includes a lower marine riser package (LMRP) 40 and a BOP or BOP stack 42. The LMRP 40 includes a riser flex joint 44, a riser adapter 46, one or more annular BOPs 48, and a pair of redundant control units or pods. A flow bore extends through the LMRP 40 from the drilling riser 26 at an upper end of the LMRP 40 to a connection at a lower end of the LMRP 40. The riser adapter 46 extends upward from the riser flex joint 44 and is coupled to a lower end of the drilling riser 26. The riser flex joint 44 enables the riser adapter 46 and the drilling riser 26 connected thereto to deflect angularly relative to the LMRP 40, while wellbore fluids flow from the wellbore 12 through the BOP stack assembly 18 into the drilling riser 26. The annular BOPs 48 each include sealing elements (e.g., elastomer; annular sealing elements) that are mechanically squeezed radially inward to seal on the conduit 32 extending through the LMRP 40 and/or to seal the flow bore. The annular BOPs 48 may have an ability to seal on a variety of tubular sizes and/or profiles, as well as perform a “Complete Shut-off” (CSO) to seal the flow bore when no tubular (e.g., the conduit 32) is positioned within the flow bore.

[0024] According to some embodiments, the BOP stack 42 includes one or more pressure sensors, choke/kill valves, and/or choke/kill lines. A main bore 52 extends through the BOP stack 42. In addition, the BOP stack 42 may include multiple axially stacked ram BOPs 54. Each ram BOP 54 may include a pair of opposed rams (e.g., ram devices; ram assemblies) and a pair of actuators (e.g., actuator assemblies) that drive the opposed rams toward and away from one another. One ram BOP 54 (e.g., an upper ram BOP) may include opposed blind shear rams that are configured to sever the conduit 32 and seal the wellbore 12 from the drilling riser 26. One ram BOP 54 (e.g., an intermediate ram BOP; a lower ram BOP) may include opposed pipe rams that are configured to engage the conduit 32 and to seal an annulus around the conduit 32 to seal the wellbore 12 from the drilling riser 26. One ram BOP 54 (e.g., an intermediate ram BOP; a lower ram BOP) may include opposed blind rams that are configured to seal the wellbore 12 from the drilling riser 26 when no tubular (e.g., the conduit 32) is positioned within the main bore 52. As shown, the BOP stack 42 includes four ram BOPs 54. However, it should be appreciated that the BOP stack 42 may include one or more of the ram BOPs 54 (e.g., any different number of rams), different types of rams, one or more annular BOPs, or combinations thereof. To facilitate discussion, the BOP stack 42 and its components may be described with reference to a vertical axis or direction 2, an axial axis or direction 4, and/or a lateral axis or direction 6.

[0025] FIG. 2 is a cross-sectional top view of a portion of an embodiment of one ram BOP 54 that may be used in the drilling system 10 of FIG. 1, in accordance with an embodiment of the present disclosure. As shown, the ram BOP 54 includes opposed rams 56 that are positioned such that the BOP 54 is in an open configuration. In the open configuration, the opposed rams 56 are withdrawn from the main bore 52, do not contact the conduit 32, and/or do not contact one another.

[0026] As shown, the BOP 54 includes a housing 58 that surrounds the main bore 52. The housing 58 is generally rectangular in the illustrated embodiment, although the housing 58 may have any cross-sectional shape, including any polygonal shape and/or annular shape. Bonnet assemblies 60 are mounted on opposite sides of the housing 58 (e.g., via threaded fasteners). Each bonnet assembly 60 supports an actuator 62 (e.g., actuator assembly), which may include a piston 64 and a connecting rod 66. The actuators 62 may drive the opposed rams 56 toward and away from one another along the axial axis 4 to transition the BOP 54 between the open configuration and a closed configuration. In the closed configuration, the opposed rams 56 are positioned within the main bore 52, contact and/or shear the conduit 32 to seal the main bore 52, and/or contact one another to seal the main bore 52. Furthermore, in the closed configuration, the wellbore fluid may provide a wellbore-assist as the wellbore fluid may flow from the main bore 52, through a cavity that houses the opposed rams 56, and into respective spaces behind the opposed rams 56 to exert respective forces on the opposed rams 56 to drive the opposed rams 56 toward one another and to hold the opposed rams 56 against one another to maintain a seal across the main bore 52. During high pressure conditions, the wellbore fluid may exert substantial respective forces on the opposed rams 56. However, during low pressure conditions, the wellbore fluid may exert small respective forces on the opposed rams 56. The features of the opposed rams 56 disclosed herein may be particularly useful during the low- pressure conditions (e.g., in the absence of the wellbore-assist), as the features of the opposed rams 56 may enable the seal across the main bore 52 to be effective during the low-pressure conditions.

[0027] Each of the opposed rams 56 may include a body 68 (e.g., ram body) that includes a forward surface 70 (e.g., side; portion; wall) and a rearward surface 72 (e.g., side; portion; wall). The forward surfaces 70 may be positioned proximate to the main bore 52 and may face one another when the opposed rams 56 are installed within the housing 58. The rearward surfaces 72 may be positioned distal from the main bore 52 and proximate to a respective one of the actuators 62 when the opposed rams 56 are installed within the housing 58. Each of the opposed rams 56 may include an attachment recess 74 (e.g., interface) that is configured to engage with the connecting rod 66 of the actuator 62. Each of the opposed rams 56 may include a seal groove 75 that supports a sealing element 76 (e.g., elastomer element), and the sealing elements 76 are configured to engage one another to form a seal to seal the main bore 52 while the BOP 54 is in the closed configuration. In FIG. 2, the sealing elements 76 have generally straight sealing edges to seal against one another to facilitate discussion; however, it should be appreciated that the sealing elements 76 may have a different shape (e.g., curved sealing edges to seal against the conduit 32).

[0028] FIG. 3 is a schematic view of a sealing assembly 100 that is formed by a first sealing element 102 and a second sealing element 104, in accordance with an embodiment of the present disclosure. It should be appreciated that the sealing assembly 100 may be used in the BOP 54 of FIG. 2 (e.g., the first sealing element 102 and the second sealing element 104 may be the sealing elements 76 on the opposed rams 56 of the BOP 54 of FIG. 2).

[0029] The first sealing element 102 and the second sealing element 104 may be formed from an elastomer material. The first sealing element 102 may include a first tapered contacting surface 106 (e.g., upwardly-facing contacting surface), and the second sealing element 104 may include a second tapered contacting surface 108 (e.g., downwardly-facing contacting surface). As shown, the first tapered contacting surface 106 tapers in a first direction along the vertical axis 2, and the second tapered contacting surface 108 tapers in a second direction along the vertical axis 2 (e.g., opposite the first direction). The first tapered contacting surface 106 may be part of a first protrusion 110 (e.g., projection) that extends from a first surface 112 (e.g., axially-faxing surface) of a first body 114 of the first sealing element 102, and the second tapered contacting surface 108 may be part of a second protrusion 116 (e.g., projection) that extends from a second surface 118 of a second body 120 of the second sealing element 104. The first protrusion 110 and the second protrusion 116 (e.g., respective points or forward-most portions of the first protrusion 110, and thus of the first tapered contacting surface 106, and the second protrusion 116, and thus of the second tapered contacting surface 108) may be offset along the vertical axis 2 so that the first tapered contacting surface 106 and the second tapered contacting surface 108 are positioned opposite to one another and/or aligned along the vertical axis 2 to facilitate contact and sealing between the first tapered contacting surface 106 and the second tapered contacting surface 108. When installed within the opposed rams, the first protrusion 110 and the second protrusion 116 extend forward of the opposed rams such that the initial contact occurs at the first tapered contacting surface 106 and the second tapered contacting surface 108 as the opposed rams transition to the closed configuration. [0030] As discussed in more detail below, the first tapered contacting surface 106 may extend laterally across the first sealing element 102, and the second tapered contacting surface 108 may extend laterally across the second sealing element 104. However, the first tapered contacting surface 106 and the second tapered contacting surface 108 may only be positioned opposite to one another (e.g., where the first tapered contacting surface 106 and the second tapered contacting surface 108 contact one another in a sealed configuration) and not on side surfaces of the first sealing element 102 and the second sealing element 104 (e.g., that are configured to contact and/or face toward a ram cavity within the housing of the BOP).

[0031] As shown in FIG. 3, the sealing assembly 100 is in an unsealed configuration in which the first sealing element 102 and the second sealing element 104 are separated from one another along the axial axis 4. FIG. 4 is a schematic view of the sealing assembly 100 in a contact configuration (e.g., intermediate configuration; at initial contact), and FIG. 5 is a schematic view of the sealing assembly 100 in a sealed configuration. Notably, FIG. 5 is merely provided to illustrate that the first sealing element 102 and the second sealing element 104 may move toward one another after the contact configuration of FIG. 4 to seal against one another, and it should be appreciated that the first sealing element 102 and the second sealing element 104 may deform into and/or assume any of a variety of shapes or configurations in the sealed configuration of FIG. 5.

[0032] In the contact configuration, the first tapered contacting surface 106 and the second tapered contacting surface 108 contact one another. In the sealed configuration, the first sealing element 102 and the second sealing element 104 are sealed against one another. The sealing assembly 100 may be adjusted from the unsealed configuration, to the contact configuration, and then to the sealed configuration by driving the first sealing element 102 and the second sealing element 104 toward one another along the axial axis 4 (e.g., via the actuators 62 in FIG. 2). Similarly, the sealing assembly 100 may be adjusted from the sealed configuration, to the contact configuration, and then to the unsealed configuration by driving the first sealing element 102 and the second sealing element 104 away from one another along the axial axis 4 (e.g., via the actuators 62 in FIG. 2). [0033] As the first tapered contacting surface 106 and the second tapered contacting surface 108 come into contact with one another, a stress (e.g., internal pressure, resultant stress) is induced at a point of contact 130 (e.g., point or region of contact). For a given force applied to the first sealing element 102 and the second sealing element 104, the stress that is induced at the point of contact 130 may be relatively high (e.g., as compared to other sealing elements that are flat and/or devoid of tapered contacting surfaces, such as devoid of the first tapered contacting surface 106 and the second tapered contacting surface 108). The stress that is induced at the point of contact 130 may be relatively high because the first tapered contacting surface 106 and the second tapered contacting surface 108 induce a bending stress, in addition to a compression stress. As shown in FIG. 4, a stress resultant, FR, may include a vertical component, FR_y, along the vertical axis 2 and a horizontal component, FR_x, along the axial axis 4. The vertical component, FR_y, may decrease a horizontal resistance to thereby enable the stress to be relatively high (e.g., for a particular force applied via the actuators 62 in FIG. 2 and as compared to the other sealing elements) to generate the sealing effect. In turn, within pressure containing equipment, this may enable the sealing assembly 100 to generate the sealing effect and to effectively provide a fluid seal for a fluid in a wide variety of conditions (e.g., to seal a wellbore while a wellbore pressure is below a wellbore-assist threshold, such as below 5, 4, 3, 2, or 1 Megapascals).

[0034] FIGS. 6-8 provide various views of a sealing element 140 that includes a straight sealing edge 142, in accordance with an embodiment of the present disclosure. In particular, FIG. 6 is a side view of the sealing element 140, FIG. 7 is a perspective view of the sealing element 140, and FIG. 8 is a top view of the sealing element 140. It should be appreciated that the sealing element 140 may be used in the sealing assembly 100 of FIG. 3 (e.g., the sealing element 140 may be the second sealing element 104 of the sealing assembly 100 of FIG. 3).

[0035] The sealing element 140 may be formed from an elastomer material. As shown, the sealing element 140 includes a tapered contacting surface 144 (e.g., upwardly-facing contacting surface), and the sealing element 140 may be configured to seal against a corresponding sealing element (e.g., that includes a downwardly-facing contacting surface) to generate a sealing effect. The tapered contacting surface 144 is part of a protrusion 146 (e.g., projection) that extends from a surface 148 (e.g., axially-faxing surface) of a body 150 of the sealing element 140. In the illustrated embodiment, the protrusion 146 includes a lip portion 152 (e.g., flexible lip) that overhangs a channel 154 (e.g., laterally- extending channel). During sealing operations, pressure may enter the channel 154 and energize the lip portion 152 to facilitate formation of a seal against the corresponding sealing element. In some embodiments, only the sealing element 140 may include the lip portion 152 (e.g., to expose the channel 154 to a high- pressure side of the sealing element 140), and the corresponding sealing element may be devoid of the lip portion 152 (e.g., has a profile similar to the first sealing element 102 in FIGS. 3-5).

[0036] As shown in FIGS. 7 and 8, the tapered contacting surface 144 may provide for the straight sealing edge 142 that extends laterally across the sealing element 140. In some embodiments, the tapered contacting surface 144 may extend across an entirety of a width of the sealing element 140 (e.g., along the lateral axis 6, from a first lateral side 156 to a second lateral side 158). Flowever, the tapered contacting surface 144 may not be positioned on the first lateral side 156 or the second lateral side 158 (e.g., so as not to contact and/or project toward a ram cavity within the housing of the BOP) of the sealing element 140. The sealing element 140 may include additional features (e.g., openings to receive fasteners) that enable the sealing element 140 to be coupled to the opposed rams 56 of the BOP 54 of FIG. 2. In some embodiments, the sealing element 140 may not include any additional features other than the features shown in FIGS. 6-8; however, it should be appreciated that the sealing element 140 may be modified or adapted with additional features.

[0037] FIGS. 9-11 provide various views of a sealing element 160 that includes a curved sealing edge 162, in accordance with an embodiment of the present disclosure. In particular, FIG. 9 is a side view of the sealing element 160, FIG. 10 is a perspective view of the sealing element 160, and FIG. 11 is a top view of the sealing element 160. It should be appreciated that the sealing element 160 may be used in the sealing assembly 100 of FIG. 3 (e.g., the sealing element 160 may be the second sealing element 104 of the sealing assembly 100 of FIG. 3).

[0038] The sealing element 160 may be formed from an elastomer material. As shown, the sealing element 160 includes a tapered contacting surface 164 (e.g., upwardly-facing contacting surface), and the sealing element 160 may be configured to seal against a conduit (e.g., the conduit 32 of FIG. 2) and to seal against a corresponding sealing element (e.g., that includes a downwardly-facing contacting surface) to generate a sealing effect. The tapered contacting surface 164 is part of a protrusion 166 (e.g., projection) that extends from a surface 168 (e.g., vertically-extending surface) of a body 170 of the sealing element 160. [0039] As shown in FIGS. 10 and 11 , the tapered contacting surface 164 may provide for the curved sealing edge 162 that extends laterally across the sealing element 160. The curved sealing edge 162 may include a center portion that includes a curved recess that is configured to receive and to seal about a conduit, such as the conduit 32 in FIG. 2. The curved sealing edge 162 may also include laterally-outer portions that include respective straight portions (e.g., straight sealing edge portions on laterally opposite sides of the curved recess). In some embodiments, the tapered contacting surface 164 may extend across an entirety of a width of the sealing element 160 (e.g., along the lateral axis 6, from a first lateral side 172 to a second lateral side 174). Flowever, the tapered contacting surface 164 may not be positioned on the first lateral side 172 or the second lateral side 174 (e.g., so as not to contact and/or project toward a ram cavity within the housing of the BOP).

[0040] While the tapered contacting surface 164 is shown as extending across the center portion that includes the curved recess (e.g., so as to contact and to seal against the conduit, such as the conduit 32 of FIG. 2) and the laterally-outer portions, it should be appreciated that the tapered contacting surface 164 may not extend across the center portion and may only extend across the laterally-outer portions. In some such cases, the center portion may be devoid of the tapered contacting surface 164 and may include a vertically-extending or flat surface to receive and to seal against the conduit. The sealing element 160 may include additional features (e.g., openings to receive fasteners) that enable the sealing element 160 to be coupled to the opposed rams 56 of the BOP 54 of FIG. 2. In some embodiments, the sealing element 160 may not include any additional features other than the features shown in FIGS. 9-11 ; however, it should be appreciated that the sealing element 160 may be modified or adapted with additional features.

[0041] While the disclosure may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. Flowever, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims. It should be appreciated that any of the features shown in FIGS. 1 -11 or described herein may be substituted and/or combined in any suitable manner. For example, the sealing element with the straight sealing edge may be devoid of a lip portion and/or the sealing element with the curved sealing edge may include the lip portion.

[0042] The techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical. Further, if any claims appended to the end of this specification contain one or more elements designated as “means for” or “step for” performing a function, it is intended that such elements are to be interpreted under 35 U.S.C. 112(f). Flowever, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).

Claims

1 . A sealing assembly configured to form a seal to separate a higher-pressure environment from a lower-pressure environment, the sealing assembly comprising: a first elastomeric member comprising a first tapered contacting surface; and a second elastomeric member comprising a second tapered contacting surface; wherein the first elastomeric member and the second elastomeric member are configured to form the seal as at least a first portion of the first tapered contacting surface and at least a second portion of the second tapered contacting surface are forced into contact with one another.

2. The sealing assembly of claim 1 , wherein the first tapered contacting surface is tapered in a first direction along a vertical axis of the sealing assembly, the second tapered contacting surface is tapered in a second direction, opposite the first direction, along the vertical axis.

3. The sealing assembly of claim 1 , wherein the first tapered contacting surface forms a first surface of a first protrusion that extends from a first body of the first elastomeric member, and the second tapered contacting surface forms a second surface of a second protrusion that extends from a second body of the second elastomeric member.

4. The sealing assembly of claim 1 , wherein a respective forward-most portion of the first tapered contacting surface and a respective forward-most portion of the second tapered contacting surface are offset along a vertical axis of the sealing assembly.

5. The sealing assembly of claim 1 , wherein the first portion of the first tapered contacting surface comprises first laterally-outer straight portions that are positioned on laterally-opposite sides of a first center curved portion of the first tapered contacting surface.

6. The sealing assembly of claim 5, wherein the second portion of the second tapered contacting surface comprises second laterally-outer straight portions that are positioned on laterally-opposite sides of a second center curved portion of the second tapered contacting surface, and the first elastomeric member and the second elastomeric member are configured to form the seal as the first laterally- outer straight portions and the second laterally-outer straight portions are forced into contact with one another and as the first center curved portion and the second center curved portion are forced into contact with a conduit.

7. The sealing assembly of claim 1 , wherein the first tapered contacting surface comprises a first lip portion that overhangs a channel that is configured to be exposed to the higher-pressure environment while the first elastomeric member and the second elastomeric member form the seal.

8. The sealing assembly of claim 1 , wherein the sealing assembly is part of opposed rams of a blowout preventer for a wellbore.

9. A pair of opposed rams for a blowout preventer, the pair of opposed rams comprising: a first ram comprising a first elastomeric member; and a second ram comprising a second elastomeric member; wherein the first elastomeric member and the second elastomeric member are configured to form a seal as at least a first portion of a first tapered contacting surface of the first elastomeric member of the first ram and at least a second portion of a second tapered contacting surface of the second elastomeric member of the second ram are forced into contact with one another.

10. The pair of opposed rams of claim 9, wherein the first tapered contacting surface is tapered in a first direction along a vertical axis of the pair of opposed rams, and the second tapered contacting surface is tapered in a second direction, opposite the first direction, along the vertical axis.

11 . The pair of opposed rams of claim 9, wherein the first tapered contacting surface forms a first surface of a first protrusion that extends forward of the first ram, and the second tapered contacting surface forms a second surface of a second protrusion that extends forward of the second ram.

12. The pair of opposed rams of claim 9, wherein a respective forward-most portion of the first tapered contacting surface and a respective forward-most portion of the second tapered contacting surface are offset along a vertical axis of the pair of opposed rams.

13. The pair of opposed rams of claim 9, wherein the pair of opposed rams comprises a pair of opposed pipe rams, and the first portion of the first tapered contacting surface comprises first laterally-outer straight portions that are positioned on laterally-opposite sides of a first center curved portion of the first tapered contacting surface.

14. The pair of opposed rams of claim 13, wherein the second portion of the second tapered contacting surface comprises second laterally-outer straight portions that are positioned on laterally-opposite sides of a second center curved portion of the second tapered contacting surface, and the first elastomeric member and the second elastomeric member are configured to form the seal as the first laterally-outer straight portions and the second laterally-outer straight portions are forced into contact with one another and as the first center curved portion and the second center curved portion are forced into contact with a conduit.

15. The pair of opposed rams of claim 9, wherein the first tapered contacting surface comprises a first lip portion that overhangs a channel that is configured to be exposed to a wellbore while the first elastomeric member and the second elastomeric form the seal.

16. A blowout preventer, comprising: a sealing assembly comprising a first elastomeric member and a second elastomeric member, wherein the first elastomeric member comprises a first tapered contacting surface and the second elastomeric member comprises a second tapered contacting surface, and the first elastomeric member and the second elastomeric member are configured to form a seal across a wellbore while at least a first portion of the first tapered contacting surface and at least a second portion of the second tapered contacting surface contact one another.

17. The blowout preventer of claim 16, wherein the blowout preventer is a ram blowout preventer comprising a first ram that supports the first elastomeric member and a second ram that supports the second elastomeric member.

18. The blowout preventer of claim 17, comprising a first actuator coupled to the first ram and a second actuator coupled to the second ram, wherein the first actuator and the second actuator are configured to drive the first ram and the second ram toward one another.

19. The blowout preventer of claim 18, wherein the first actuator and the second actuator are configured to drive the first ram and the second ram toward one another to enable the first elastomeric member and the second elastomeric member to form the seal across the wellbore while a wellbore pressure is below a wellbore-pressure assist threshold.

20. The blowout preventer of claim 16, wherein the first tapered contacting surface is tapered in a first direction along a vertical axis of the blowout preventer, and the second tapered contacting surface is tapered in a second direction, opposite the first direction, along the vertical axis.