US20190345790A1

US20190345790A1 - Injectable Seal for A Blowout Preventer

Info

Publication number: US20190345790A1
Application number: US15/978,171
Authority: US
Inventors: Christopher Nault; Matthew David Givens; Michael Mancuso
Original assignee: Cameron International Corp
Current assignee: Cameron International Corp
Priority date: 2018-05-13
Filing date: 2018-05-13
Publication date: 2019-11-14

Abstract

A supplemental sealing system for a blowout preventer (BOP) includes a fluid source configured to support a sealing fluid and a conduit fluidly coupled to the fluid source. The conduit is configured to deliver the sealing fluid from the fluid source to a bore of the BOP to enable the sealing fluid to supplement a seal formed by one or more primary seal elements of the BOP.

Description

BACKGROUND

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 and/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.
A blowout preventer (BOP) stack is installed on a wellhead to seal and control an oil and gas well during drilling operations. A drill string may be suspended inside a drilling riser from a rig through the BOP stack into the well bore. During drilling operations, 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 well bore. In the event of a rapid invasion of formation fluid in the annulus, commonly known as a “kick,” the BOP stack may be actuated to seal the annulus and to control fluid pressure in the wellbore, thereby protecting well equipment disposed above the BOP stack.

BRIEF DESCRIPTION OF THE DRAWINGS

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:

FIG. 1 is a schematic diagram of an embodiment of an offshore system having a supplemental sealing system;

FIG. 2 is a cross-sectional side view of an embodiment of a portion of a blowout preventer (BOP) that may be used in the offshore system of FIG. 1, wherein a ram of the BOP is in an open position;

FIG. 3 is a cross-sectional side view of the portion of the BOP of FIG. 2, wherein the ram is in a closed position;

FIG. 4 is a cross-sectional side view of an embodiment of a portion of a BOP that may be used in the offshore system of FIG. 1, wherein the BOP includes a conduit extending through a connecting rod of a ram;

FIG. 5 is a schematic view of an embodiment of shear rams that may be used in a BOP of the offshore system of FIG. 1, wherein a seal is formed at least in part by a sealing fluid injected into the BOP; and

FIG. 6 is a flow diagram of an embodiment of a method for sealing a wellbore using the supplemental sealing system of FIG. 1.

DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS

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.
The present embodiments are generally directed to systems and methods for sealing a wellbore. More particularly, the present embodiments are directed to systems and methods that provide a sealing fluid (e.g., an injectable sealing fluid) to a blowout preventer (BOP) to seal the wellbore. Generally, rams of a BOP move from an open position in which the rams are withdrawn from the wellbore to enable fluid flow across the BOP to a closed position in which the rams seal the wellbore to block fluid flow across the BOP using sealing technology (e.g., elastomer seal elements). The sealing fluid may be injected into the wellbore or a bore of the BOP proximate to the rams of the BOP (e.g., on a high-pressure side of a seal formed by one or more seal elements of the BOP). The sealing fluid may flow into crevices, voids, or gaps in the one or more seal element that form the seal, and the sealing fluid may then change state (e.g., from a liquid to a solid) to form a sealing material that supplements (e.g., restores, repairs, patches, or enhances) the seal formed by the one or more seal elements.
Various sealing fluids are envisioned. For example, the sealing fluid may include multiple different fluids that are injected separately and that change state to form the sealing material upon mixing with one another. In some embodiments, the sealing fluid may change state to form the sealing material in response to high pressure or other conditions within the wellbore. It should also be understood that the sealing fluid and any other fluids (e.g., solvent) disclosed herein are not intended to be limited to liquid matter, but instead may be any injectable matter, including any liquid, gas, solid, or any combination thereof. For example, the sealing fluid may be a liquid containing small particles (e.g., solid particles), which may act as a coagulant or otherwise assist in the transition to the solid state to form the sealing material.
With the foregoing in mind, FIG. 1 is an embodiment of an offshore system 10. The offshore system 10 includes an offshore vessel or platform 12 at a sea surface 14. A BOP stack 16 is mounted to a wellhead 18 at a sea floor 20. A tubular drilling riser 22 extends from the platform 12 to the BOP stack 16. The riser 22 may return drilling fluid or mud to the platform 12 during drilling operations. Downhole operations are carried out by a tubular string 24 (e.g., drill string, production tubing string, or the like) that extends from the platform 12, through the riser 22, through a bore 25 of the BOP stack 16, and into a wellbore 26.
To facilitate discussion, the BOP stack 16 and its components may be described with reference to an axial axis or direction 30, a longitudinal axis or direction 32, and a lateral axis or direction 34. As shown, the BOP stack 16 includes multiple BOPs 36 (e.g., ram BOPs) axially stacked (e.g., along the axial axis 30) relative to one another. As discussed in more detail below, each BOP 36 includes a pair of longitudinally opposed rams and corresponding actuators 38 that actuate and drive the rams toward and away from one another along the longitudinal axis 32. Although four BOPs 36 are shown, the BOP stack 16 for subsea applications may include any suitable number of BOPs (e.g., 3 or more ram BOPs with the ability to seal and 1 or more annular BOPs with the ability to seal). Additionally, the BOP stack 16 may include any of a variety of different types of rams. For example, in certain embodiments, the BOP stack 16 may include one or more BOPs 36 having opposed shear rams or shearing surfaces configured to sever the tubular string 24, and one or more BOPs 36 having opposed pipe rams configured to engage the tubular string 24 and to seal the bore 25 (i.e., the annulus around the tubular string 24 disposed within the bore 25). A supplemental sealing system 40 may provide one or more sealing fluids (e.g., injectable sealing fluids) to one or more BOPs 36.
FIG. 2 is a cross-sectional side view of an embodiment of a portion of one BOP 36 in an open position 50, and FIG. 3 is a cross-sectional side view of the portion of the BOP 36 in a closed position 52. In the open position 50, each ram 54 is withdrawn from the bore 25 and/or does not contact the corresponding opposed ram 54. In the closed position 52, each ram 54 is advanced into the bore 25 and/or contacts a respective opposing ram 54. In the closed position 52, the rams 54 may seal the bore 25 and/or may block a flow of fluid from the wellbore 26 (FIG. 1) through the bore 25.
As shown, the BOP 36 includes a support structure having a housing 56 that defines ram-supporting cavities 57 and the bore 25. The housing 56 is generally rectangular in the illustrated embodiment, although the housing 56 may have any cross-sectional shape, including any polygonal shape or an annular shape. In the illustrated embodiment, the support structure includes a bonnet assembly 58 mounted to the housing 56 (e.g., via threaded fasteners). The bonnet assembly 58 may support the actuators 38, which each include a piston 60 and a connecting rod 62. The actuators 38 may drive the rams 54 toward and away from one another along the longitudinal axis 32 and through the bore 25 to adjust the BOP 36 between the open position 50 and the closed position 52. The illustrated actuators 38 include hydraulically operated pistons 60 movably positioned within chambers 88, although any of a variety of actuators may be employed to drive the rams 54 toward and away from one another.
To facilitate discussion, the illustrated rams 54 are shear and seal rams that include one or more shearing surface 63 configured to shear the tubular string 24 and to seal the bore 25, thereby isolating equipment vertically above the BOP 36 from the wellbore 26 (FIG. 1) vertically below the BOP 36. The rams 54 include a first ram 64 (e.g., upper ram) and a second ram 66 (e.g., lower ram), and the BOP 36 includes a sealing system that seals the bore 25 when the BOP 36 is in the closed position 52. In the illustrated embodiment, the sealing system includes one or more sealing assemblies having one or more seal elements (e.g., primary seal elements) that form a seal (e.g., primary seal) across the bore 25 when the BOP 36 is in the closed position 52. More particularly, the first ram 64 includes a first seal assembly 67 having a first seal element 68 (e.g., laterally-extending seal) positioned along a first surface 70 (e.g., axially-facing surface) of a body 72 of the first ram 64. The first seal element 68 is configured to seal against an opposed surface 74 (e.g., axially-facing surface) of the second ram 66 when the BOP 36 is in the closed position 52. As shown, the first seal assembly 67 also includes a second seal element 76 (e.g., laterally-extending seal) that is positioned along an outer surface 78 (e.g., axially-facing surface) of the body 72 of the first ram 64 and is configured to seal against the housing 56 of the BOP 36.
In the illustrated embodiment, the second ram 66 includes a second seal assembly 77 having a second seal element 80 (e.g., laterally-extending seal) that is positioned along an outer surface 82 (e.g., axially-facing surface) of a body 84 of the second ram 66 and is configured to seal against the housing 56 of the BOP 36. Together, the first and second sealing assemblies 67, 77 form a seal across the bore 25 when the BOP 36 is in the closed position 52. It should be appreciated that the first and second sealing assemblies 67, 77 may include additional seal elements, some or all of the illustrated seal elements may be omitted, and/or the various seal elements may be positioned at other locations of the rams 54 or at other components of the BOP 36. For example, the first seal element 68 may be positioned along an axially-extending surface or at any other surface of the first or second ram 64, 66 that enables the first seal element 68 to form a seal between the rams 54. Furthermore, the BOP 36 may include additional sealing assemblies or seal elements that isolate the bore 25 from other equipment and the environment. For example, the illustrated embodiment includes annular seal elements 86 supported in the bonnet 58 to seal against the connecting rod 62, thereby isolating the chambers 88 from the bore 25. The seal elements disclosed herein may be elastomer seals, metal seals, or any other suitable type of seal.
It is now recognized that it may be desirable to supplement the seal formed by the one or more sealing assemblies of the BOP 36 when the rams 54 are in the closed position 52, thus ensuring that the one or more sealing assemblies of the BOP 36 seal the bore 25 in the expected manner and/or at the expected locations. For example, certain well operators may wish to strengthen the seal formed by the one or more sealing assemblies or provide additional sealing material across the bore 25 once the rams 54 reached the closed position 52. In some cases, one or more seal elements of the one or more sealing assemblies of the BOP 36 may be worn and/or may be unable to reliably seal the bore 25.
Accordingly, the illustrated embodiment includes the supplemental sealing system 40 to deliver or inject one or more sealing fluids to supplement the seal formed by the one or more sealing assemblies (e.g., the first and second sealing assemblies 67, 77) of the BOP 36. In the illustrated embodiment, the supplemental sealing system 40 includes a first fluid source 100 that supports a sealing fluid and is fluidly coupled to a first conduit 102 that extends through the housing 56 to an outlet 103 at the bore 25. The supplemental sealing system 40 also includes a second fluid source 104 that supports a sealing fluid and is fluidly coupled to a second conduit 106 that extends through the housing 56 to an outlet 107 the bore 25.
In operation, as the rams 54 are driven to the closed position 52 or at any time before or after the rams 54 reach the closed position 52, the supplemental sealing system 40 may inject one or more sealing fluids proximate to the rams 54 (e.g., on an upstream side [toward the wellbore 26, FIG.1] of the seal formed by the one or more sealing assemblies or axially below the one or more sealing assemblies). The one or more sealing fluids may flow into crevices, voids, or gaps in the seal elements, and the one or more sealing fluids may then change state to form a sealing material that supplements the seal formed by the one or more sealing assemblies of the BOP 36. Thus, in the illustrated embodiment, the seal across the bore 25 may be formed in part by the sealing material. The high pressure in the bore 25 axially below the one or more sealing assemblies drives the one or more sealing fluids toward the rams 54, and any leak path in the one or more sealing assemblies of the rams 54 may draw the one or more sealing fluids toward the crevices, breaks, voids, or gaps creating the leak path to facilitate sealing the bore 25. It should be appreciated that the one or more sealing fluids may supplement the seal by forming a new seal (e.g., physically separate from the seal elements) between components of the BOP 36 (e.g., filling voids or gaps between the opposed rams 54 or between the opposed rams 54 and the housing 56, and without flowing into voids or gaps in the seal elements).
The supplemental sealing system 40 may have various features. In the illustrated embodiment, the first fluid source 100 and the first conduit 102 may provide a first type of fluid to the bore 25, while the second fluid source 104 and the second conduit 106 may provide a second, different type of fluid to the bore 25. The first and second fluids may change state to form a sealing material upon mixing with one another. Thus, the first and second fluids may be capable of being injected into the bore 25, flowing toward the one or more sealing assemblies of the BOP 26 (e.g., flowing toward the crevices, voids, or gaps creating the leak path), and then mixing and changing state at the appropriate location to supplement the seal.
In some embodiments, the first fluid source 100 and the first conduit 102 may provide the same type of fluid to the bore 25 as the second fluid source 104 and the second conduit 106. Such a configuration may enable the supplemental sealing system 40 to provide the sealing fluid at different axial and/or circumferential locations within the bore 25 and/or at various locations relative to the bore 25 (e.g., within the ram-supporting cavities 57), which may enable the sealing fluid to efficiently reach various seal elements of the one or more sealing assemblies. It should be appreciated that, in such cases, multiple conduits (e.g., the first conduit 102 and the second conduit 106) may extend from one fluid source (e.g., the first fluid source 100). The conduits (e.g., the first conduit 102 and the second conduit 106) utilized to deliver the sealing fluid may be existing or unused choke/kill ports of the BOP 36, or may be formed as new conduits uniquely used for injection of the sealing fluid.
Furthermore, the supplemental sealing system 40 may provide the sealing fluid at the different locations simultaneously or the supplemental sealing system 40 may selectively provide the sealing fluid at one or more particular locations closest to a suspected leak path (e.g., based on sensor data, such as pressure data, obtained from one or more sensors positioned about the BOP 36 or axially above the BOP 36). For example, the sensor data may be received and processed at a controller 112 (e.g., electronic controller having a processor 114 and memory 116) within or communicative coupled to the supplemental sealing system 40, and the supplemental sealing system 40 may then selectively deliver the sealing fluid based on the sensor data or based on any other factors, such as a position of the rams 54 (e.g., whether the BOP 36 is in the open position 50 or the closed position 52). In some embodiments, an operator may receive an indication of the sensor data and may provide an input the to the controller 112 to instruct the supplemental sealing system 40 to selectively deliver the fluid based on the sensor data or based on any other factors. In general, it should be appreciated that the supplemental sealing system 40 may be operated by the controller 112 sending actuation signals to valve actuators 118 that adjust valves 120 from closed positions to open positions to deliver the respective fluid from the respective fluid source to the bore 25 of the BOP 36. The controller 112 may control (or be part of a control system that controls) movement of the rams 54 and operation of the supplemental sealing system 40, and thus, the movement of the rams 54 and delivery of the sealing fluid may be coordinated (e.g., the sealing fluid may be delivered automatically in response to the rams 54 moving toward or reaching the closed position 52).
The processor 114 may be used to execute software. Moreover, the processor 108 may include multiple microprocessors, one or more “general-purpose” microprocessors, one or more special-purpose microprocessors, and/or one or more application specific integrated circuits (ASICS), or some combination thereof. For example, the processor 112 may include one or more reduced instruction set (RISC) processors. The memory 116 may include a volatile memory, such as random access memory (RAM), and/or a nonvolatile memory, such as read only memory (ROM). The memory 116 may store a variety of information and may be used for various purposes. For example, the memory 116 may store processor-executable instructions (e.g., firmware or software) for the processor 114 to execute, such as instructions for controlling the one or more valve actuators 118.
As noted above, any of a variety of sealing fluids are envisioned. For example, the supplemental sealing system 40 may inject two different types of sealing fluids that form the sealing material upon mixing with one another and/or in response to being subjected to high pressure or other conditions within the bore 25 over time. Such fluids may include a two-part epoxy, including an epoxy resin and a hardener or other catalyst that form a solid sealing material upon mixing and/or being subjected to conditions within the bore 25 over time. In some embodiments, the supplemental sealing system 40 may inject a single type of sealing fluid that forms the sealing material in response to being subjected to high pressure or other conditions within the bore 25 over a period of time. Such fluids may include an epoxy resin or a viscous fluid or foam that forms a solid sealing material upon being subjected to conditions within the bore 25 over time.
In certain embodiments, it may be desirable to remove (e.g., dissolve or break down) the sealing material when the seal is no longer needed, such as prior to, during, or after adjustment of the BOP 36 from the closed position 52 to the open position 50. For example, a solvent (e.g., fluid capable of removing the sealing material, preferably without affecting or degrading any primary sealing material or seal elements) may be provided through a conduit (e.g., through one of the conduits 102, 106 at a separate time from the sealing fluid or through a dedicated conduit) to the bore 25. In the illustrated embodiment, the supplemental sealing system 40 includes a third fluid source 108 (e.g., solvent fluid source) that supports a solvent, and the third fluid source 108 is fluidly coupled to a third conduit 110 (e.g., solvent conduit) that extends through the housing 56 to an outlet 109 at the bore 25. The third conduit 110 may be positioned to provide the solvent at any of a variety of locations, such as on an upstream side of the sealing material, within the bore 25, and/or within the ram-supporting cavities 57, to enable the solvent to remove the sealing material. The controller 112 may control delivery of the solvent based on sensor data and/or position of the rams 54, such as automatically delivering the solvent in response to the rams 54 moving toward or reaching the open position 50. In some embodiments, a bore cleaning tool may be inserted into the bore 25 (e.g., from the surface) and may be operated to physically remove (e.g., mill or scrape) the sealing material from the BOP 36.
As noted above, the sealing fluid and/or the solvent may be provided at any of a variety of locations of the BOP 26. FIG. 4 is a cross-sectional side view of an embodiment of a portion of the BOP 36 having a ram-supported conduit 130 extending through the connecting rod 62 to deliver the sealing fluid and/or the solvent to the bore 25. More particularly, in the illustrated embodiment, the ram-supported conduit 130 is fluidly coupled to a respective fluid source 132 and extends longitudinally through the connecting rod 62 to an outlet 134 at a sidewall 136 (e.g., annular wall) of the connecting rod 62. The fluid may flow from the outlet 134 into the ram-supporting cavity 57, as shown by arrow 138. When the fluid is a sealing fluid, the sealing fluid may flow into crevices, voids, or gaps in the seal elements that form the seal across the bore 25, and the sealing fluid may then change state to form a sealing material that supplements the seal formed by the seal elements. When the fluid is a solvent, the solvent may flow toward the sealing material to facilitate removal of the sealing material from the BOP 36.
It should be appreciated that one or more ram-supported conduits may be provided in one or both connecting rods 62 of the BOP 36 to provide multiple different fluids and/or to provide one or more fluids at multiple locations. It should also be appreciated that one or more ram-supported conduits (e.g., ram-supported conduit 130 in FIG. 4) and the conduits through the housing 56 (e.g., conduits 102, 106 in FIGS. 2 and 3) may be provided to inject the sealing fluids and/or the solvent into various locations of the BOP 36. Indeed, any of the features disclosed in FIGS. 1-4 may be combined in any suitable manner to carry out the techniques disclosed herein.
FIG. 5 is a schematic view of shear rams 54 that may be used in the BOP 36, in accordance with an embodiment of the present disclosure. The shear rams 54 are shown separated from one another to facilitate discussion; however, it should be understood that respective opposed faces 140 of the rams 54 may contact one another when the BOP 36 is in the closed position 52, as shown in FIGS. 3 and 4. More particularly, the shearing surfaces 63 may overlap in the longitudinal direction 32, longitudinally opposed front seal elements 142 may contact one another, side seal elements 144 may contact the housing 56 (FIGS. 2-4), and the second seal elements 76, 80 may also contact the housing 56. The first seal element 68 (FIGS. 2-4) may be provided on one of the rams 54 to extend axially between the rams 54. The various seal elements 68, 76, 80, 142, and 144 form the first and second sealing assemblies 67, 77 that are designed to form the seal across the bore 25 when the BOP 36 is in the closed position 52.
As shown, at least part of the seal may be supplemented or formed by a sealing material 148 (e.g., supplemental sealing material or supplemental seal) injected via the supplemental sealing system 40 (FIGS. 1-4). While the sealing material 148 is shown within (e.g., within a void) of one of the front seal elements 142, it should be appreciated that any of the seal elements disclosed herein or any other portion of the BOP 25 may be supplemented or sealed by the sealing material 148.
It should also be appreciated that the supplemental sealing system 40 disclosed herein may be used with any of a variety of other types of rams (e.g., pipe rams or blind rams) in the BOP 36. Furthermore, the supplemental sealing system 40 may be utilized with other types of equipment within the mineral extraction system 10, such as annular blowout preventers, diverters, or valves (e.g., ball valves or gate valves). The supplemental sealing system 40 may also be utilized with subsea systems as well as with land-based or onshore systems.
FIG. 6 is a flow chart illustrating a method 150 for sealing the wellbore 26 using the supplemental sealing system 40, in accordance with an embodiment of the present disclosure. The method 150 includes various steps represented by blocks. It should be noted that some or all of the steps of the method 150 may be performed as an automated procedure by a system, such as the supplemental sealing system 40 having the controller 112. Although the flow chart illustrates the steps in a certain sequence, it should be understood that the steps may be performed in any suitable order and certain steps may be carried out simultaneously, where appropriate. The method 150 for sealing the wellbore 26 using the supplemental sealing system 40 may be initiated automatically (e.g., in response to initiation of movement of the rams 54, the rams 54 reaching the closed position 52, or receipt of sensor data indicative of a potential leak path) or in response to operator input to the supplemental sealing system 40.
The method 150 may begin by adjusting the BOP 36 from the open position 50 to the closed position 52, in step 152. As the rams 54 are driven to the closed position 52 or at any time before or after the rams 54 reach the closed position 52, the supplemental sealing system 40 may inject one or more sealing fluids proximate to the rams 54 (e.g., on an upstream side of the seal formed by the one or more sealing assemblies or axially below the one or more sealing assemblies), in step 154. The one or more sealing fluids may flow into crevices, breaks, voids, or gaps, and the one or more sealing fluids may then change state to form a sealing material that supplements the seal formed by the one or more sealing assemblies of the BOP 36. As noted above, the high pressure in the bore 25 axially below the one or more sealing assemblies drives the one or more sealing fluids toward the rams 54, and any leak path in the one or more sealing assemblies of the rams 54 may draw the one or more sealing fluids toward the crevices, breaks, voids, or gaps creating the leak path to facilitate sealing the bore 25.
In certain embodiments, it may be desirable to remove (e.g., dissolve or break down) the supplemental sealing material when the seal is no longer needed, such as prior to, during, or after adjustment of the BOP 36 from the closed position 52 to the open position 50. Thus, a solvent may be injected proximate to the sealing material to remove the sealing material, at step 154. Additionally or alternatively, in some embodiments, a bore cleaning tool may be inserted into the bore 25 and may be operated to physically remove (e.g., mill or scrape) the supplemental sealing material from the BOP 36.
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. However, 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.

Claims

1. A supplemental sealing system for a blowout preventer (BOP), comprising:

a fluid source configured to support a sealing fluid; and

a conduit fluidly coupled to the fluid source, wherein the conduit is configured to deliver the sealing fluid from the fluid source to a bore of the BOP to enable the sealing fluid to supplement a seal formed by one or more primary seal elements of the BOP.

2. The system of claim 1, wherein the conduit comprises an outlet positioned on an upstream side of the seal formed by the one or more primary seal elements of the BOP.

3. The system of claim 1, wherein the conduit extends through a housing of the BOP.

4. The system of claim 1, wherein the conduit extends through a connecting rod coupled to a ram of the BOP.

5. The system of claim 1, comprising a second fluid source configured to support a second sealing fluid, and a second conduit fluidly coupled to the second fluid source, wherein the second conduit is configured to deliver the second sealing fluid to the bore of the BOP to enable the second sealing fluid to supplement the seal formed by one or more primary seal elements of the BOP.

6. The system of claim 5, wherein respective outlets of the conduit and the second conduit are positioned at different axial locations, different circumferential locations, or both relative to the bore of the BOP.

7. The system of claim 1, comprising a solvent fluid source configured to support a solvent, and a solvent conduit fluidly coupled to the solvent fluid source, wherein the solvent conduit is configured to deliver the solvent to the bore of the BOP to enable the solvent to remove a sealing material formed by the sealing fluid from the BOP.

8. The system of claim 1, comprising a controller configured to instruct a valve actuator to adjust a valve to enable flow of the sealing fluid to the bore of the BOP in response to receipt of a signal indicating that the BOP will be moved to a closed position or is in the closed position.

9. The system of claim 1, comprising a controller configured to instruct a valve actuator to adjust a valve to enable flow of the sealing fluid to the bore of the BOP in response to receipt of a signal indicating a potential leak path while the BOP is in a closed position.

10. A blowout preventer (BOP) system, comprising:

a housing configured to support opposed rams of a BOP;

one or more primary seal elements configured to form a seal across a bore of the BOP when the opposed rams are in a closed position; and

a supplemental sealing system configured to inject a sealing fluid proximate to the one or more primary seal elements to enable the sealing fluid to supplement the seal.

11. The system of claim 10, wherein the supplemental sealing system comprises a fluid source configured to support the sealing fluid, and a conduit fluidly coupled to the fluid source and to the bore of the BOP.

12. The system of claim 11, wherein the conduit comprises an outlet positioned on an upstream side of the seal formed by the one or more primary seal elements of the BOP.

13. The system of claim 11, wherein the conduit extends through the housing of the BOP.

14. The system of claim 11, wherein the conduit extends through a connecting rod coupled to one ram of the opposed rams.

15. The system of claim 10, wherein the supplemental sealing system is configured to independently provide two different fluids to the bore of the BOP to enable mixing of the two different fluids within the bore to supplement the seal.

16. A method for sealing a bore of a blowout preventer (BOP):

providing a sealing fluid from a fluid source to a bore of the BOP via a conduit; and

supplementing a seal formed by one or more primary seal elements of the BOP using the sealing fluid within the bore.

17. The method of claim 16, comprising providing a second sealing fluid from a second fluid source to the bore of the BOP via a second conduit, wherein supplementing the seal formed by one or more primary seal elements of the BOP using the sealing fluid within the bore comprises mixing the sealing fluid and the second sealing fluid within the bore to form a sealing material.

18. The method of claim 16, comprising injecting a solvent into the bore of the BOP to dissolve a sealing material formed by the sealing fluid.

19. The method of claim 16, comprising providing the sealing fluid in response to receipt of a signal indicating that the BOP will be moved to a closed position or is in the closed position.

20. The method of claim 16, comprising providing the sealing fluid in response to receipt of a signal indicating a potential leak path while the BOP is in a closed position.