BACKGROUND OF THE INVENTION

[0001] A conventional closed-loop hydraulic drilling system uses a managed pressure drilling (“MPD”) system to manage wellbore pressure through the application of surface backpressure during drilling and other operations. The MPD system typically includes an annular sealing system, an annular closing system, and a flow diverter, which are typically deployed together as part of an integrated MPD riser joint.

[0002] The annular sealing system is disposed above, and in fluid communication with, the annular closing system, and the annular closing system is disposed above, and in fluid communication with, the flow diverter. The annular sealing system seals the annulus surrounding the drill string, thereby allowing for the application of surface backpressure by adjusting the choke position of one or more choke valves of an MPD choke manifold disposed on the surface. The MPD choke manifold fluidly connects the flow diverter to the mud-gas separator (“MGS”), shale shakers, or other fluids processing system used to recycle and reuse drilling fluids. The annular closing system provides a redundant seal to the annulus surrounding the drill string in the event the annular sealing system is being installed, serviced, replaced, or otherwise fails.

[0003] The MPD system may be used, for example, to manage wellbore pressure within a pressure gradient bounded by the pore pressure and the fracture pressure, to prevent the unintended influx of formation fluids or damage the structural integrity of the wellbore. Notwithstanding, the MPD system may be used in a wide variety of MPD applications including, but not limited to, applied surface backpressure-MPD (“ASBP-MPD”) and pressurized mud cap drilling (“PMCD”) operations.

[0004] In deepwater and ultra-deepwater environments where drillers are pursuing increasingly difficult well plans, the ability to accurately manage wellbore pressure is critical to the economic feasibility and safety of operations.

BRIEF SUMMARY OF THE INVENTION

[0005] According to one aspect of one or more embodiments of the present invention, a deepwater managed pressure drilling joint includes an annular sealing system, a topside housing disposed above the annular sealing system, a bottom-side housing disposed below the annular sealing system, and a subsea choke valve comprising a first port that fluidly communicates the interior of the bottom-side housing with a valve and a second port that fluidly communicates the valve with the interior of the top-side housing. The subsea choke valve controllably communicates a bottom-side annulus within the bottom-side housing with a top-side annulus within the top-side housing when the annular sealing system is engaged around a drill string.

[0006] According to one aspect of one or more embodiments of the present invention, a closed-loop hydraulic drilling system includes an upper portion of a marine riser system, a lower portion of the marine riser system, a deepwater managed pressure drilling joint disposed between the upper portion and the lower portion of the marine riser system, a subsea blowout preventer that fluidly communicates the lower portion of the marine riser system with a wellbore, and a data acquisition and control system that controls a choke aperture setting of a subsea choke valve of the deepwater managed pressure drilling joint. The deepwater managed pressure drilling joint discharges returning fluids from a bottom-side annulus formed in a bottom-side housing of the deepwater managed pressure drilling joint to a top-side annulus formed in a top-side housing of the deepwater managed pressure drilling joint via the subsea choke valve for discharge via the rig diverter.

[0007] According to one aspect of one or more embodiments of the present invention, a method of managed pressure drilling includes sealing an annulus surrounding a drill pipe, fluidly communicating an interior of a bottom-side housing disposed directly below the annular seal with an interior of top-side housing disposed directly above the annular seal through a subsea choke valve, and controlling application of backpressure through manipulation of a choke aperture of the subsea choke valve. Returning fluids may be diverted from a bottom-side annulus within the bottom-side housing, through the subsea choke valve, to a top-side annulus within the top-side housing for discharge through a rig diverter of an upper portion of a marine riser system.

[0008] Other aspects of the present invention will be apparent from the following description and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0009] FIG. 1 shows a conventional closed-loop hydraulic drilling system for drilling an offshore subterranean wellbore. [0010] FIG. 2 shows a deepwater MPD joint in accordance with one or more embodiments of the present invention.

[0011] FIG. 3A shows a cross-sectional view of an annular sealing system of a deepwater MPD joint with a seal and bearing assembly in accordance with one or more embodiments of the present invention.

[0012] FIG. 3B shows top plan view of an annular sealing system of a deepwater MPD joint with a seal and bearing assembly in accordance with one or more embodiments of the present invention.

[0013] FIG. 4 A shows a cross-sectional view of an annular sealing system of a deepwater MPD joint with a reinforced sealing element and an annular packer in a disengaged state in accordance with one or more embodiments of the present invention.

[0014] FIG. 4B shows a cross-sectional view of an annular sealing system of a deepwater MPD joint with a reinforced sealing element and an annular packer in an engaged state in accordance with one or more embodiments of the present invention.

[0015] FIG. 5A shows a cross-sectional view of an annular sealing system of a deepwater MPD joint with an annular packer in a disengaged state in accordance with one or more embodiments of the present invention.

[0016] FIG. 5B shows a cross-sectional view of an annular sealing system of a deepwater MPD joint with an annular packer in an engaged state in accordance with one or more embodiments of the present invention.

[0017] FIG. 6 shows a closed-loop hydraulic drilling system with a deepwater MPD joint in accordance with one or more embodiments of the present invention for drilling an offshore subterranean wellbore.

[0018] FIG 7 shows a data acquisition and control system in accordance with one or more embodiments of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

[0019] One or more embodiments of the present invention are described in detail with reference to the accompanying figures. For consistency, like elements in the various figures are denoted by like reference numerals. In the following detailed description of the present invention, specific details are described to provide a thorough understanding of the present invention. In other instances, aspects that are well- known to those of ordinary skill in the art are not described to avoid obscuring the description of the present invention.

[0020] FIG. 1 shows a conventional closed-loop hydraulic drilling system 100 for drilling an offshore subterranean wellbore. A floating drilling rig (not shown) is typically disposed on a body of water (not shown). A marine riser system 102 facilities drilling and other operations from a platform of the drilling rig (not shown). Upper portion 104 of marine riser system 102 typically includes one or more of a rig diverter 106, a ball joint 108, a telescopic joint 110, and termination joint 112, where telescopic joint 110 articulates to accommodate the heaving motion of the body of water (not shown) in which the drilling rig (not shown) is situated. However, the components, as well as the configuration of components, used in upper portion 104 of marine riser system 102 may vary based on an application or design. MPD riser joint 114 is typically disposed in between, and in fluid communication with, telescopic joint 110 and lower portion 116 of marine riser system 102. Lower portion 116 of marine riser system 102 is disposed above, and in fluid communication with, a subsea blowout preventer (“SSBOP”) 118. SSBOP 118 is typically disposed at or near the sea floor (not shown) above wellbore 120 being drilled. A drill string 122 may be disposed through a central lumen that extends through upper portion 104 of marine riser system 102, MPD riser joint 114, lower portion 116 of marine riser system 102, SSBOP 118, and into wellbore 120. A distal end of drill string 122 may include a bottomhole assembly or drill bit 124 for drilling wellbore 120.

[0021] MPD riser joint 114 is typically assembled onshore and delivered to the rig (not shown) as a unitaiy joint for deployment. MPD riser joint 114 typically includes an annular sealing system 126 disposed above, and in fluid communication with, an annular closing system 128. Annular closing system 128 is disposed above, and in fluid communication with, a flow diverter 130. Flow diverter 130 is disposed above, and in fluid communication with, a lower portion 116 of marine riser system 102. Annular sealing system 126 typically includes a rotating control device (“RCD”), an active control device (“ACD”), or other type or kind of annular sealing system 126 that seals annulus 132 surrounding drill string 122 while drill string 122 is rotated. Annular closing system 128 typically serves as a redundant annular seal that may be engaged when annular sealing system 126, or components thereof, are being installed, serviced, removed, or otherwise disengaged. Flow diverter 130 diverts returning fluids from annulus 132 below the annular seal to the drilling rig (not shown). Flow diverter 130 is in fluid communication with a distribution manifold 134 that is in fluid communication with one or more choke valves of an MPD choke manifold 136, disposed on the surface on the drilling rig (not shown). MPD choke manifold 136 is in fluid communication with a mud-gas separator 138, shale shaker 140, or other fluids processing system (not shown) that receive returning fluids to be recycled for reuse. The processed fluids (not shown) may be diverted to an active mud system 142 that sources drilling fluids for one or more mud pumps 144. During drilling operations, one or more mud pumps 144 may controllably inject drilling fluids (not shown) into an interior passageway of drill string 122 for operative use.

[0022] During conventional drilling operations, a data acquisition and control system 400 may receive pressure sensor and flow rate data in approximate or near real-time. One of ordinary skill in the art will recognize that near real-time means data is received very nearly when measured, delayed by measurement, calculation, or transmission only. The data acquisition and control system 400 may control the flow rate of mud pumps 144, thereby controlling the injection rate of fluids downhole. In addition, data acquisition and control system 400 may command one or more choke valves of MPD choke manifold 136 to a desired choke aperture setting, thereby controlling the flow out. As noted above, the pressure tight seal on annulus 132 provided by annular sealing system 126 allows for the control of wellbore pressure by manipulation of the choke aperture, or position, of one or more choke valves of MPD choke manifold 136 and the corresponding application of surface backpressure. The choke aperture of MPD choke manifold 136 corresponds to an amount, typically represented as a percentage, that MPD choke manifold 136 is open and capable of flowing. For example, each choke valve of MPD choke manifold 136 may be fully opened, fully closed, or somewhere in between with a plurality of intermediate settings that refer to some degree of openness. If the choke operator wishes to increase wellbore 120 pressure, the choke aperture of MPD choke manifold 136, or chokes thereof, may be reduced to further restrict fluid flow and apply additional surface backpressure. Similarly, if the choke operator wishes to decrease wellbore 120 pressure, the choke aperture of MPD choke manifold 136, or chokes thereof, may be increased to increase fluid flow and reduce the amount of applied surface backpressure. As such, conventional MPD riser joint 114 may be used to manage wellbore pressure by manipulating the choke aperture of MPD choke manifold 136, based on, at least in part, pressure sensor data. In this way, wellbore pressure may be managed by manipulating the flow rates of mud pumps 144 and managing the application of surface backpressure through manipulation of one or more chokes of the MPD choke manifold 136 that control the diversion of returning fluids to the drilling rig (not shown) through a number of specialized equipment disposed on the drilling rig (not shown).

[0023] While the advantages of MPD drilling techniques are well known in the industry, the decision to implement MPD on a particular drilling rig for a particular well is a complex decision that includes technical as well as economic considerations. In high risk wells, MPD may be a technical necessity. In such cases, the decision to implement MPD is readily made in the affirmative, so long as doing so is economically feasible. However, even when an MPD riser joint is deployed, MPD techniques are only used some of the time because certain hole sections do not require MPD, MPD is only needed to maintain bottomhole pressure during connections, or some subset of features of the MPD system are needed. Notwithstanding, there are a substantial number of drilling rigs and applications where there may be a desire to use MPD, but the economic costs of implementing MPD outweigh the benefits of adoption of MPD. The economic costs associated with MPD include the cost of the MPD riser joint itself, delivery to an offshore location, installation, operation, and ongoing maintenance as well as control systems and training on-rig personnel in its use, some costs of which are influenced by the size of the integrated MPD riser joint. In lower specification rigs and wells, MPD simply is not an option as there are no MPD offerings on the market that meet both the technical requirements as well as the economic constraints of the application.

[0024] Accordingly, in one or more embodiments of the present invention, a simplified and uniquely integrated deepwater MPD joint provides essential MPD functionality at a substantially lower cost and in a substantially smaller footprint. The deepwater MPD joint implements a new design that uses existing flow paths to reduce or eliminate the need for certain specialized equipment in the pressurized fluid return path, including the discrete flow diverter, distribution manifold, and MPD choke manifold. A subsea choke valve may be integrated and disposed underwater and divert returning fluids from the bottom-side annulus below the annular seal to a topside annulus above the annular seal for return through the upper portion of the marine riser system for discharge by the rig diverter. As such, the deepwater MPD joint reduces acquisition, transport, installation, and operational costs, as well as systemic costs associated with the MPD drilling system, thereby enabling the adoption and use of MPD techniques in applications that were previously not economically feasible.

[0025] FIG. 2 shows a deepwater MPD joint 200 in accordance with one or more embodiments of the present invention. Deepwater MPD joint 200 may be used in place of, for example, a conventional MPD riser joint (e.g., 114 of FIG. 1) and reduces or eliminates the need for certain specialized equipment (e.g., 128, 130, 134, and 136 of FIG. 1) as part of the drilling rig (not shown) as discussed herein.

[0026] In one or more embodiments of the present invention, deepwater MPD j oint 200 may include an annular sealing system 230, a top-side housing 220 disposed above, or otherwise attached to a top portion of, annular sealing system 230, a bottom-side housing 240 disposed below, or otherwise attached to a bottom portion of, annular sealing system 230, and a subsea choke valve 270. In certain embodiments, subsea choke valve 270 may include a first port 268 that fluidly communicates an interior of bottom-side housing 240 with a choke valve (not independently illustrated) and a second port 269 that fluidly communicates the choke valve (not independently illustrated) with an interior of top-side housing 220. The choke valve (not independently illustrated) may be any type or kind of valve mechanism that provides a controllable choke aperture between the first port 268 and the second port 269. The choke aperture, or position, of the choke valve (not independently illustrated) may be fully opened, fully closed, or somewhere in between with a plurality of intermediate settings that refer to some degree of openness. The choke aperture may be controlled by a data acquisition and control system (e.g., 400 of FIG. 1) disposed on the surface. Subsea choke valve 270 may controllably fluidly communicate a bottom-side annulus 132 within bottom-side housing 240 with a top-side annulus 232 within top-side housing 220 when annular sealing system 230 is engaged to seal the annulus surrounding drill pipe 122. In this way, subsea choke valve 270, disposed underwater, may controllably fluidly communicate the interior of bottom-side housing 240 and the interior of top-side housing 220, thereby diverting returning fluids through topside annulus 232.

[0027] In certain embodiments, a top-side flange 210 may be disposed on a top distal end of top-side housing 220 and facilitate connection to the next joint in the upper portion of the marine riser system (not shown). Similarly, a bottom-side flange 250 may be disposed on a bottom distal end of bottom-side housing 240 and facilitate connection to the next joint in the lower portion of the marine riser system (not shown). In certain embodiments, an optional bottom-side isolation valve 260 may be disposed between bottom-side housing 240 and first port 268 of subsea choke valve 270. When included, bottom-side isolation valve 260 may govern fluid communication between subsea choke valve 270 and the interior of bottom-side housing 240. Similarly, an optional top-side isolation valve 280 may be disposed between top-side housing 220 and second port 269 of subsea choke valve 270. When included, top-side isolation valve 280 may govern fluid communication between subsea choke valve 270 and the interior of top-side housing 220. The isolation valves 260, 280 may be controlled by the data acquisition and control system (e.g., 400 of FIG. 1) disposed on the drilling rig (not shown) or physically controlled by divers or remotely operated vehicles (not shown).

[0028] In one or more embodiments of the present invention, annular sealing system 230 may be disposed in between top-side housing 220 and bottom-side housing 240. In certain embodiments, annular sealing system 230 may be an RCD. In other embodiments, annular sealing system 230 may be an ACD. In still other embodiments, annular sealing system 230 may be any other type or kind of sealing system, including hybrids thereof, capable of sealing annulus 132 surrounding drill string 122. Annular sealing system 230 may include one or more of an annular sealing system housing (not shown), an annular packer (not shown), and/or a removably disposed annular sealing element (not shown). In embodiments that include a removable annular sealing element (not shown), the removable annular sealing element (not shown) may be, for example, a seal and bearing assembly (e.g., 310 of FIG. 3), a reinforced sealing element (e.g., 410 of FIG. 4) or any other type or kind of sealing element suitable for forming an annular seal. In embodiments that include a removable sealing element (not shown), a plurality of locking dogs (not shown) or any other locking and retention mechanism may be used to secure the removable sealing element (not shown) in place for operative use. However, in certain embodiments, annular sealing system 230 may not require a removable sealing element (not shown) and instead rely on only an annular packer (e.g., 510 of FIG. 5) to create the annular seal.

[0029] The data acquisition and control system (e.g., 400 of FIG. 1) disposed on the drilling rig (not shown) may command subsea choke valve 270, via, for example, a surface-to-water cable assembly (not shown), to a desired choke aperture, or position, corresponding to a desired amount of backpressure to be applied. For example, annular sealing system 230 may be engaged forming a pressure-tight annular seal around drill string 122 below annular sealing system 230. Bottom-side isolation valve 260 and top-side isolation valve 280, if included, may be in their opened state, permitting fluid flow. Similar to conventional MPD systems, the data acquisition and control system (e.g., 400 of FIG. 1), or choke operator, may manage wellbore pressure by manipulation of the choke aperture of subsea choke valve 270 and the corresponding application of backpressure. In contrast to conventional MPD systems, instead of using a discrete flow diverter (e.g., 130 of FIG. 1) that diverts returning fluids from bottom-side annulus 132 to the distribution manifold (e.g., 134 of FIG. 1) and the MPD choke manifold (e.g., 136 of FIG. 1) on the surface for processing, deepwater MPD joint 200 may controllably divert returning fluids from bottom-side annulus 132 through subsea choke valve 270, disposed underwater, and into top-side annulus 232. In this way, wellbore pressure may be managed by the application of backpressure and returning fluids from bottom-side annulus 132 may be controllably diverted through top-side annulus 232 for discharge by the rig diverter (e.g., 106 of FIG. 1) to the fluids processing systems (e.g., 138 or 140 of FIG. 1) disposed on the drilling rig (not shown).

[0030] Advantageously, deepwater MPD joint 200 presents a lower cost, smaller footprint, MPD solution that provides essential MPD functionality while reducing or eliminating the requirement for specialized equipment such as an annular closing system (e.g., 128 of FIG. 1), a flow diverter (e.g., 130 of FIG. 1), distribution manifold (e.g., 134 of FIG. 1), or MPD choke manifold (e.g., 136 of FIG. 1).

[0031] FIG. 3A shows a cross-sectional view of an RCD-type annular sealing system 230 of a deepwater MPD joint (e.g., 200 of FIG. 2) with a seal and bearing assembly 300 in accordance with one or more embodiments of the present invention. Seal and bearing assembly 300 may include a non-rotating portion 310, a rotating portion 320, and a sealing element 330. The seal and bearing assembly 300 may be disposed within a RCD housing 340. Drill pipe 122 may be disposed through a center lumen that extends from end to end of seal and bearing assembly 300. Drill pipe 122 may be disposed through the central lumen of sealing element 330 with an interference fit. A portion of sealing element 330 may extend below rotating portion 320 and nonrotating portion 310, thereby sealing the annulus surrounding drill pipe 122. Rotating portion 320 may rotate with drill pipe 122 relative to non-rotating portion 310 that is fixed with respect to RCD housing 340. One of ordinary skill in the art will recognize that the size, shape, and design of seal and bearing assembly 300 of an RCD-type annular sealing system may vary based on an application or design in accordance with one or more embodiments of the present invention.

[0032] FIG. 3B shows top-plan view of a seal and bearing assembly 300 of an RCD- type annular sealing system 230 of a deepwater MPD joint (e.g., 200 of FIG. 2) in accordance with one or more embodiments of the present invention. As shown in this plan view, drill pipe 122 may be disposed through a central lumen of sealing element 330 with an interference fit. Rotating portion 320 allows sealing element 330, and drill pipe 122 disposed therethrough, to rotate relative to the fixed non-rotating portion 310. Non-rotating potion 310 may be secured (not shown) to an RCD housing 340 that holds seal and bearing assembly 300 fixedly in place. Seal and bearing assembly 300 may be secured to RCD housing 340 by a plurality of locking dogs (not shown) or any other type or kind of locking mechanism (not shown).

[0033] FIG. 4A shows a cross-sectional view of an ACD-type annular sealing system 230 of a deepwater MPD joint (e.g., 200 of FIG. 2) with a reinforced sealing element 410 and an annular packer 420 in a disengaged state in accordance with one or more embodiments of the present invention. Annular sealing system 230 may be used to controllably seal the annulus surrounding drill pipe 122, thereby allowing for the application of surface backpressure as previously discussed. Reinforced sealing element 410 may be a substantially cylindrical member with a central lumen 132 that extends from end to end along a central axis that receives drill pipe 122 therethrough. However, reinforced sealing element 410 may vary in shape or size based on an application or design. Reinforced sealing element 410 may include a reinforcement cage 440 disposed within, or co-molded with, a flexible material 450 capable of deforming when engaged by annular packer 420. Reinforcement cage 440 may be a pattern or arrangement of material capable of flexing and resistant to wear from contact with rotating drill pipe 122. Flexible material 450 may permeate or extend through substantial portions of reinforcement cage 440 such that, when engaged, on an inner diameter of reinforced sealing element 410, a portion of reinforcement cage 440 and flexible material 450 make contact and form a pressure-tight seal (not shown) with drill pipe 122 while resisting wear from the rotation of drill pipe 122. While various flexible honeycomb-like shapes (not independently shown) may advantageously be used, the pitch, pattern, arrangement, size, and shape of reinforcement cage 440 may vary based on an application or design in accordance with one or more embodiments of the present invention. Operatively, reinforced sealing element 410 may be disposed on a mandrel (not independently illustrated) that is removably disposed within a housing 460 and secured in place, at least partially, within an inner diameter of annular packer 420, with a plurality of locking dogs or other locking mechanism (not shown) of the deepwater MPD joint (e.g., 200 of FIG. 2).

[0034] In certain embodiments, reinforcement cage 440 may be composed of a polytetrafluoroethylene (“PTFE”) material co-molded with flexible material composed of urethane 450. In other embodiments, reinforcement cage 440 may be composed of a synthetic fluoropolymer material co-molded with flexible material composed of an elastomer 450. One of ordinary skill in the art will recognize that the material composition of reinforcement cage 440 may vary based on an application or design in accordance with one or more embodiments of the present invention. In addition, one of ordinary skill in the art will also recognize that reinforcement cage 440 may be composed of any flexible wear resistant material suitable for making contact with a rotating drill pipe 122 and facilitating the formation of a pressure-tight seal. In certain embodiments, flexible material 450 may be composed of an elastomer, urethane, polyurethane, nitrile butadiene, or combinations thereof. One of ordinary skill in the art will recognize that the material composition of flexible material 450 may vary based on an application or design and may be composed of any flexible material suitable for flexing and facilitating formation of a pressure-tight seal in accordance with one or more embodiments of the present invention. Advantageously, reinforcement cage 440 and flexible material 450 may flex and deform in such a way that reinforcement cage 440 and flexible material 450 controllably make contact and form a pressure-tight seal with drill pipe 122 during rotation as shown in FIG. 4B and described herein.

[0035] Continuing, FIG. 4B shows a cross-sectional view of an ACD-type annular sealing system 230 of the deepwater MPD joint (e.g., 200 of FIG. 2) with reinforced sealing element 410 and annular packer 420 in an engaged state in accordance with one or more embodiments of the present invention. Annular packer 420 may include an elastomer or rubber body, with a plurality of fingers or protrusions 470, that travels within housing 360 when a hydraulically actuated piston 480 is actuated. Specifically, hydraulic actuation (not shown) causes piston 480 to travel upwards and in turn causes annular packer 420 to travel within housing 460 such that elastomer portions of annular packer 420 squeeze against drill pipe 122 disposed therethrough, forming a pressure tight seal. The contact causes reinforced sealing element 410 to flex inwards such that the inner diameter of sealing element 410 squeezes drill pipe 122 disposed therethrough, forming a pressure-tight seal even while drill pipe 122 is being rotated. Reinforcement cage 440 has a material composition that resists wear, thereby prolonging the usable life of reinforced sealing element 410. However, over time, reinforced sealing element 410 will wear to the extent that it struggles to, or is no longer able to, maintain the pressure-tight seal on the annulus, at which point it will require replacement. Since reinforced sealing element 410 is removably disposed, it may be easily removed and replaced with a new reinforced sealing element 410 as needed.

[0036] FIG. 5A shows a cross-sectional view of an ACD-like annular sealing system 230 of a deepwater MPD joint (e.g., 200 of FIG. 2) with an annular packer 510 in a disengaged state in accordance with one or more embodiments of the present invention. In certain applications, the deepwater MPD joint (e.g., 200 of FIG. 2) may not be required to provide certain MPD functionality, but may serve simply as a riser- gas-handling (“RGH”) system. In such applications, annular sealing system 230 may not require the same degree of pressure containment as other embodiments. In contrast to embodiments that use a reinforced sealing element 410 of FIG. 4, in one or more embodiments of the present invention, annular sealing system 230 may not use a sealing element (e.g., 410 of FIG. 4) and rely on annular packer 510 alone. Annular packer 510 may be substantially similar or even identical to annular packer 420 but may vary in size or shape since it does not require use of a sealing element (e.g., 410 of FIG. 4). Annular packer 510 may have a size and shape that facilitates travel within housing 460 such that it deforms, makes contact with, and forms a pressure-tight seal with drill pipe 122. Annular packer 510 may include a central lumen 132 that extends from end to end along a central axis that receives drill pipe 122 therethrough. Annular packer 510 may be composed of a flexible and wear resistant material 420 having a high resiliency, high load bearing capacity, high impact resistance, high abrasion resistance, and/or high tear resistance that is capable of deforming when engaged by annular packer 510. Operatively, drill pipe 122 may disposed through the central lumen 132 of annular packer 510. In certain embodiments, annular packer 510 may be composed of elastomer, rubber, or combinations thereof. One of ordinary skill in the art will recognize that the material composition of annular packer 510 may vary based on an application or design and may be composed of any flexible material suitable for flexing and facilitating formation of a pressure-tight seal in accordance with one or more embodiments of the present invention. Advantageously, annular packer 510 may deform in such a way that annular packer 510 controllably makes contact and forms a pressure-tight seal with drill pipe 122 during rotation as shown in FIG. 5B and described herein.

[0037] Continuing, FIG. 5B shows a cross-sectional view of an ACD-like annular sealing system 230 of a deepwater MPD joint (e.g., 200 of FIG. 2) with annular packer 510 in an engaged state in accordance with one or more embodiments of the present invention. Annular packer 510 may include an elastomer or rubber body, a plurality of fingers or protrusions 520, that travels within housing 360 when a hydraulically actuated piston 480 is actuated. Specifically, hydraulic actuation (not shown) causes piston 480 to travel upwards and in turn causes annular packer 510 to travel within housing 460 such that elastomer portions of annular packer 510 squeeze against drill pipe 122 disposed therethrough, forming a pressure tight seal. Over time, annular packer 510 will wear to the extent that it struggles to, or is no longer able to, maintain the pressure-tight seal on the annulus, at which point it will require replacement. Since annular packer 510 is not disposed on a mandrel, the removal and replacement may be more complicated than embodiments in which removably disposed sealing elements element (e.g., 410 of FIG. 4) are used.

[0038] FIG. 6 shows a closed-loop hydraulic drilling system 600 with a deepwater MPD system 200 in accordance with one or more embodiments of the present invention for drilling an offshore subterranean wellbore. A floating drilling rig (not shown) may be disposed on a body of water (not shown). A marine riser system 102 may facilitate drilling and other operations from a platform of the drilling rig (not shown). Upper portion 104 of marine riser system 102 typically includes one or more of a rig diverter 106, a ball joint 108, a telescopic joint 110, and termination joint 112, where telescopic joint 110 articulates to accommodate the heaving motion of the body of water (not shown) in which the drilling rig (not shown) is situated. However, the components, as well as the configuration of components, used in upper portion 104 of marine riser system 102 may vary based on an application or design. Deepwater MPD joint 200 may be disposed in between, and in fluid communication with, telescopic joint 110 and lower portion 116 of marine riser system 102. Lower portion 116 of marine riser system 102 may be disposed above, and in fluid communication with, a subsea blowout preventer (“SSBOP”) 118. SSBOP 118 may be disposed at or near the sea floor (not shown) above wellbore 120 being drilled. A drill string 122 may be disposed through a central lumen that extends through upper portion 104 of marine riser system 102, deepwater MPD j oint 200, lower portion 116 of marine riser system 102, SSBOP 118, and into wellbore 120. A distal end of drill string 122 may include a bottomhole assembly or drill bit 124 for drilling wellbore 120.

[0039] Data acquisition and control system 400, typically disposed on the drilling rig (not shown), may command the subsea choke valve (e.g., 270 of FIG.2) of deepwater MPD joint 200, via a surface-to- water cable assembly (not shown), to a desired choke aperture, or position, corresponding to a desired amount of backpressure to be applied. For example, annular sealing system (e.g., 230 of FIG. 2) may be engaged forming a pressure-tight annular seal around drill string 122 below annular sealing system (e.g., 230 of FIG. 2). Bottom-side isolation valve (e.g., 260 of FIG. 2) and top-side isolation valve (e.g., 280 of FIG.2), if included, may be in their opened state, permitting fluid flow. Similar to conventional MPD systems, the data acquisition and control system (e.g., 400 of FIG. 1), or choke operator, may manage wellbore pressure by manipulation of the choke aperture of the subsea choke valve (e.g., 270 of FIG. 2) and the corresponding application of backpressure. In contrast to conventional MPD systems, instead of using a discrete flow diverter (e.g., 130 of FIG. 1) that diverts returning fluids from bottom-side annulus 132 to the distribution manifold (e.g., 134 of FIG. 1) and the MPD choke manifold (e.g., 136 of FIG. 1) on the surface for processing, deepwater MPD joint 200 may controllably divert returning fluids from bottom-side annulus 132 through subsea choke valve (e.g., 270 of FIG. 2), disposed underwater, and into top-side annulus (e.g., 232 of FIG. 2). In this way, wellbore pressure may be managed by the application of backpressure and returning fluids from bottom-side annulus 132 may be controllably diverted through top-side annulus (e.g., 232 of FIG. 2) for discharge by the rig diverter 106 to the shale shakers 140 disposed on the drilling rig (not shown).

[0040] Advantageously, deepwater MPD joint 200 presents a lower cost, smaller footprint, MPD solution that provides essential MPD functionality while reducing or eliminating the requirement for specialized equipment such as an annular closing system (e.g., 128 of FIG. 1), a flow diverter (e.g., 130 of FIG. 1), distribution manifold (e.g., 134 of FIG. 1), or MPD choke manifold (e.g., 136 of FIG. 1). [0041] In one or more embodiments of the present invention, a method of managed pressure drilling may include sealing an annulus surrounding a drill pipe, fluidly communicating an interior of a bottom-side housing disposed directly below the annular seal with an interior of top-side housing disposed directly above the annular seal through a subsea choke valve, and controlling the application of backpressure through manipulation of the choke aperture of the choke valve of the subsea choke valve. Returning fluids may be diverted from a bottom-side annulus within the bottom-side housing, through the subsea choke valve, to a top-side annulus within the top-side housing for discharge through the rig diverter of the upper portion of the marine riser system.

[0042] FIG. 7 shows a data acquisition and control system 400 in accordance with one or more embodiments of the present invention. In certain embodiments, a data acquisition and control system 400 may include one or more of a Central Processing Unit (“CPU”) 705, a host bridge 710, an Input/Output (“IO”) bridge 715, a Graphics Processing Unit (“GPUs”) 725, an Application-Specific Integrated Circuit (“ASIC”) (not shown), and a Programmable Logic Controller (“PLC”) (not shown) disposed on one or more printed circuit boards (not shown) that perform computational or logical operations. Each CPU 705, GPU 725, ASIC (not shown), and PLC (not shown) may be a single-core device or a multi-core device. Multi-core devices typically include a plurality of cores (not shown) disposed on the same physical die (not shown) or a plurality of cores (not shown) disposed on multiple die (not shown) that are collectively disposed within the same mechanical package (not shown).

[0043] CPU 705 may be a general-purpose computational device that executes software instructions. CPU 705 may include one or more of an interface 708 to host bridge 710, an interface 718 to system memory 720, and an interface 723 to one or more IO devices, such as, for example, one or more GPUs 725. GPU 725 may serve as a specialized computational device that performs graphics functions related to frame buffer manipulation. However, one of ordinary skill in the art will recognize that GPU 725 may be used to perform non-graphics related functions that are computationally intensive. In certain embodiments, GPU 725 may interface 723 directly with CPU 705 (and indirectly interface 718 with system memory 720 through CPU 705). In other embodiments, GPU 725 may interface 721 directly with host bridge 710 (and indirectly interface 716 or 718 with system memory 720 through host bridge 710 or CPU 705 depending on the application or design). In still other embodiments, GPU 725 may directly interface 733 with 10 bridge 715 (and indirectly interface 716 or 718 with system memory 720 through host bridge 710 or CPU 705 depending on the application or design). One of ordinary skill in the art will recognize that GPU 725 includes on-board memory as well. The functionality of GPU 725 may be integrated, in whole or in part, with CPU 705 and/or host bridge 710.

[0044] Host bridge 710 may be an interface device that interfaces between the one or more computational devices and IO bridge 715 and, in some embodiments, system memory 720. Host bridge 710 may include an interface 708 to CPU 705, an interface 713 to IO bridge 715, for embodiments where CPU 705 does not include an interface 718 to system memory 720, an interface 716 to system memory 720, and for embodiments where CPU 705 does not include an integrated GPU 725 or an interface 723 to GPU 725, an interface 721 to GPU 725. The functionality of host bridge 710 may be integrated, in whole or in part, with CPU 705 and/or GPU 725.

[0045] IO bridge 715 may be an interface device that interfaces between the one or more computational devices and various IO devices (e.g., 740, 745) and IO expansion, or add-on, devices (not independently illustrated). IO bridge 715 may include an interface 713 to host bridge 710, one or more interfaces 733 to one or more IO expansion devices 735, an interface 738 to keyboard 740, an interface 743 to mouse 745, an interface 748 to one or more local storage devices 750, and an interface 753 to one or more network interface devices 755. The functionality of IO bridge 715 may be integrated, in whole or in part, with CPU 705 and/or host bridge 710. Each local storage device 750, if any, may be a solid-state memory device, a solid-state memory device array, a hard disk drive, a hard disk drive array, or any other non- transitory computer readable medium. Network interface device 755 may provide one or more network interfaces including any network protocol suitable to facilitate networked communications.

[0046] Data acquisition and control system 400 may include one or more network- attached storage devices 760 in addition to, or instead of, one or more local storage devices 750. Each network-attached storage device 760, if any, may be a solid-state memory device, a solid-state memory device array, a hard disk drive, a hard disk drive array, or any other non-transitory computer readable medium. Network-attached storage device 760 may or may not be collocated with data acquisition and control system 400 and may be accessible to data acquisition and control system 400 via one or more network interfaces provided by one or more network interface devices 755. [0047] One of ordinary skill in the art will recognize that data acquisition and control system 400 may be a conventional computing system or an application-specific computing system (not shown). In certain embodiments, an application-specific computing system (not shown) may include one or more ASICs (not shown) or programmable logic controllers (“PLCs”) (not shown) that perform one or more specialized functions in a more efficient manner. The one or more ASICs (not shown) may interface directly with CPU 705, host bridge 710, or GPU 725 or interface through IO bridge 715. Alteratively, in other embodiments, an application-specific computing system (not shown) may be reduced to only those components necessary to perform a desired function or functions in an effort to reduce one or more of chip count, printed circuit board footprint, thermal design power, and power consumption. The one or more ASICs (not shown) or PLCs (not shown) may be used instead of one or more of CPU 705, host bridge 710, IO bridge 715, or GPU 725. In such systems, the one or more ASICs (not shown) or PLCs (not shown) may incorporate sufficient functionality to perform certain network, computational, or logical functions in a minimal footprint with substantially fewer component devices.

[0048] As such, one of ordinary skill in the art will recognize that CPU 705, host bridge 710, IO bridge 715, GPU 725, ASIC (not shown), or PLC (not shown) or a subset, superset, or combination of functions or features thereof, may be integrated, distributed, or excluded, in whole or in part, based on an application, design, or form factor in accordance with one or more embodiments of the present invention. Thus, the description of data acquisition and control system 400 is merely exemplary and not intended to limit the type, kind, or configuration of component devices that constitute a data acquisition and control system 400 suitable for performing computing operations in accordance with one or more embodiments of the present invention. Notwithstanding the above, one of ordinary skill in the art will recognize that data acquisition and control system 400 may be an industrial, standalone, laptop, desktop, server, blade, or rack mountable system and may vary based on an application or design.

[0049] Advantages of one or more embodiments of the present invention may include, but is not limited to, one or more of the following:

[0050] In one or more embodiments of the present invention, a deepwater MPD joint provides essential MPD functionality at a substantially lower cost and in a substantially smaller footprint. [0051] In one or more embodiments of the present invention, a deepwater MPD joint implements a new design that uses existing flow paths to reduce or eliminate the use of certain specialized equipment in the pressurized fluid return path, including the discrete flow diverter, distribution manifold, and MPD choke manifold.

[0052] In one or more embodiments of the present invention, a deepwater MPD joint integrates a subsea choke valve that is disposed underwater that diverts returning fluids from the annulus below the annular seal to an annulus above the annular seal for return through the upper portion of the marine riser system for discharge by the rig diverter.

[0053] In one or more embodiments of the present invention, a deepwater MPD joint enables the adoption of MPD in low specification or cost constrained applications that otherwise would not be able to use conventional MPD systems for cost reasons.

[0054] In one or more embodiments of the present invention, a deepwater MPD joint reduces acquisition, transportation, installation, and operational costs associated with implementing an MPD system.

[0055] In one or more embodiments of the present invention, a deepwater MPD joint does not require a discrete flow diverter, distribution manifold, or MPD choke manifold thereby reducing systemic costs associated with the MPD drilling system thereby enabling the adoption and use of MPD techniques in applications that were previously not considered economically feasible.

[0056] While the present invention has been described with respect to the above-noted embodiments, those skilled in the art, having the benefit of this disclosure, will recognize that other embodiments may be devised that are within the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the appended claims.