HYBRID ROTATING SEALING ELEMENT AND HYBRID ANNULAR SEALING SYSTEM

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001]This application is a bypass continuation of PCT International Application PCT/US 2024/038575, filed on Jul. 18, 2024, which claims the benefit of, or priority to, U.S. Provisional Patent Application 63/527,390, filed on Jul. 18, 2023, both of which are hereby incorporated by reference in their entirety.

BACKGROUND OF THE INVENTION

[0002]In drilling operations, drilling fluid, sometimes referred to as mud, is circulated through the wellbore. The drilling fluid is critical to maintaining primary well control through the application of hydrostatic pressure. In conventional drilling operations, the wellbore is open to the atmosphere at the surface such that the pressure at the top of the fluid column is atmospheric. Under static conditions, such as when a drill pipe connection is made, the pressure at the bottom of the wellbore is substantially determined by the weight of the fluid column in the well. As such, under static conditions, the hydrostatic pressure at the bottom of the well is a function of the density of the drilling fluid and the depth of the well.

[0003]To drill ahead to extend the depth of the wellbore, the drilling rig must circulate drilling fluid to cool and lubricate the bit, remove cuttings, and maintain wellbore stability. As the circulation or flow rate increases, frictional pressures are created as fluid particles interact with the drill string, the wellbore, and other fluid particles. These interactions cause the bottomhole pressure to increase as a function of the fluid flow rate of drilling fluid through the well. While the amount of friction acting at any depth may vary through optimization of the fluid composition, flow rate, and tubular design, there is no way to completely eliminate friction from the well. As such, under circulating conditions, the hydrostatic pressure at the bottom of the well is a function of the density of the drilling fluid, the depth of the well, and friction influenced by the composition of the drilling fluid, flow rate, and tubular design. Thus, the drilling rig typically sees bottomhole pressure that is substantially equivalent to the hydrostatic pressure when the mud pumps are off and higher when the mud pumps are on, due to friction.

[0004]Under conventional drilling practice, new footage may be drilled as long the pressure of the fluid in the wellbore is greater than the pore pressure and less than the fracture pressure of all the open hole, or uncased, formations. If the static downhole pressure in the wellbore is less than the pore pressure of the adjacent rock, the drilling rig risks taking an influx of fluid, commonly referred to as a kick. If the flowing downhole pressure in the wellbore is greater than the fracture pressure of the adjacent rock, the rig risks fracturing the rock. Each of these scenarios may give rise to significant complications including a blowout or underground blowout. Therefore, the drilling crew must carefully maintain the drilling fluid composition such that the static downhole pressure in the wellbore is greater than the pore pressure of the adjacent rock and such that the dynamic downhole pressure in the wellbore is less than the fracture pressure of the adjacent rock for every open hole formation simultaneously. When it is not possible to achieve this with a single drilling fluid, the drilling rig must stop drilling and set a casing to protect vulnerable formations.

[0005]In Applied Surface Back Pressure (“ASBP”) Managed Pressure Drilling (“MPD”) applications, an annular sealing system, such as a Rotating Control Device (“RCD”) or non-rotating Active Control Device (“ACD”) commercially offered by National Oilwell Varco, L.P., are used to create an annular seal on the wellbore above the blowout preventer (“BOP”). Drilling returns are diverted from below the annular seal to the surface through the dedicated MPD choke manifold. The MPD choke manifold typically includes an array of sensors for measuring the pressure, temperature, and flow rate of the fluid and a plurality of choke valves that are commanded by a control system to a desired choke aperture.

[0006]Contemporary MPD systems use a conventional hydraulic model to estimate downhole conditions based on static and/or dynamic data to determine an optimal surface pressure at the MPD choke manifold that maintains a constant downhole pressure. While the drilling rig is circulating drilling fluid through the drill string, the choke aperture of the MPD choke manifold is partly or mostly open to maintain a lower surface pressure. However, when circulation is stopped, the choke aperture of the MPD choke manifold is moved to a more closed position to achieve a higher fluid pressure at the surface. Pressure applied to the wellbore at the surface, by way of the MPD choke manifold, increases the bottomhole pressure by a substantially equal amount. While there is no way to entirely eliminate friction from the well, the use of ASBP MPD techniques allow the rig crew, or the control system if automated, to trade applied surface back pressure for downhole circulating friction pressure as the flow rate through the well varies, thereby stabilizing downhole pressures and maintaining a constant downhole pressure at a defined depth. The annular sealing system is critically important to create the annular seal, maintain wellbore pressure, and enable the controlled application of surface back pressure.

SUMMARY OF THE INVENTION

[0007]According to one aspect of one or more embodiments of the present invention, a hybrid rotating sealing element for an annular packer system includes a seal and bearing housing including an external sealing feature disposed about an outer portion of the seal and bearing housing, where the external sealing feature prevents leakage through the annular packer system when an annular packer of the annular packer system is actuated, an internal mandrel disposed within an inner aperture of the seal and bearing housing, a plurality of upper tapered-thrust bearings mounted at an offset angle to the seal and bearing housing, a plurality of upper jam nuts to adjust a preload of the upper tapered-thrust bearings, a plurality of lower tapered-thrust bearings mounted at the offset angle to the seal and bearing housing, a plurality of lower jam nuts to adjust a preload of the lower tapered-thrust bearings, a preload spacer disposed between the upper and the lower tapered-thrust bearings, an upper seal carrier disposed on a top side of the seal and bearing housing including a plurality of upper dynamic sealing elements that contact the internal mandrel and a plurality of upper static sealing elements that contact the seal and bearing housing, a lower seal carrier disposed on a bottom side of the seal and bearing housing including a plurality of lower dynamic sealing elements that contact the internal mandrel and a plurality of lower static sealing elements that contact the seal and bearing housing, a first interference-fit sealing element attached to a bottom distal end of the internal mandrel.

[0008]According to one aspect of one or more embodiments of the present invention, a hybrid ACD annular sealing system includes an upper connection end including an upper flange, an upper tubular portion, and an upper plurality of downward travel locking dogs disposed about the upper tubular portion, an upper annular packer system including an upper arcuate housing, an upper annular packer including an upper plurality of protrusions disposed within the upper arcuate housing, and a central lumen through the upper annular packer, an intermediate tubular portion including an upper intermediate plurality of downward travel locking dogs disposed about the intermediate tubular portion and a lower intermediate plurality of downward travel locking dogs disposed about the intermediate tubular portion, a lower annular packer system including a lower arcuate housing, a lower annular packer including a lower plurality of protrusions disposed within the lower arcuate housing, and the central lumen through the lower annular packer, a lower connection end including a lower flange, a lower tubular portion, and a lower plurality of downward travel locking dogs disposed about the lower tubular portion, where an upper hydraulically actuated piston causes the upper annular packer to travel within the upper arcuate housing narrowing the central lumen to form sealing engagement with a hybrid rotating sealing element or cause an actively controlled non-rotating ACD sealing element to flex to form sealing engagement with drill pipe, tubulars, or tools disposed through the central lumen, and where a lower hydraulically actuated piston causes the lower annular packer to travel within the lower arcuate housing narrowing the central lumen to form sealing engagement with a hybrid rotating sealing element or cause an actively controlled non-rotating ACD sealing element to flex to form sealing engagement with drill pipe, tubulars, or tools disposed through the central lumen.

[0009]According to one aspect of one or more embodiments of the present invention, a hybrid MPD integrated riser joint including a hybrid ACD annular sealing system, an annular closing system disposed below and in fluid communication with the hybrid ACD annular sealing system, and a flow diverter disposed below and in fluid communication with the annular closing system, where a hydraulically actuated piston causes an annular packer of the annular closing system to travel within an arcuate housing of the annular closing system narrowing a central lumen of the annular packer to form sealing engagement with a hybrid rotating sealing element that forms sealing engagement with drill pipe, tubulars, or tools disposed through the central lumen.

[0010]According to one aspect of one or more embodiments of the present invention, a hybrid ACD annular closing system including an upper connection end including an upper flange, an upper tubular portion, and an upper plurality of downward travel locking dogs disposed about the upper tubular portion, an annular packer system including an arcuate housing, an annular packer including a plurality of protrusions disposed within the arcuate housing, and a central lumen through the annular packer, and a lower connection end including a lower flange, a lower tubular portion, and a lower plurality of downward travel locking dogs disposed about the lower tubular portion, where a hydraulically actuated piston causes the annular packer to travel within the arcuate housing narrowing the central lumen to form sealing engagement with a hybrid rotating sealing element or cause an actively controlled non-rotating ACD sealing element to flex to form sealing engagement with drill pipe, tubulars, or tools disposed through the central lumen.

[0011]According to one aspect of one or more embodiments of the present invention, a downward travel locking dog includes an actuation end comprising a hydraulically actuated piston, a housing, and an extendable engagement end having an angled face on a first side and a recessed flat surface on a second side, where the hydraulically actuated piston controllably drives the engagement end outwards and the recessed flat surface is recessed from the body portion to enable downward travel of a sealing element or tool when engaging.

[0012]Other aspects of the present invention will be apparent from the following description and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0013]FIG. 1 shows a schematic of a closed-loop hydraulic drilling system for drilling an offshore subterranean wellbore.

[0014]FIG. 2 shows an MPD riser joint including an ACD annular sealing system, annular closing system, and flow diverter.

[0015]FIG. 3A shows a cross-sectional perspective view of an actively controlled ACD sealing element of an ACD annular sealing system.

[0016]FIG. 3B shows a cross-sectional elevation view of the actively controlled ACD sealing element of the ACD annular sealing system.

[0017]FIG. 4A shows a cross-sectional detailed view of an actively controlled ACD sealing element disposed within an annular packer system of an ACD annular sealing system, where the annular packer is in an unactuated and disengaged state.

[0018]FIG. 4B shows a cross-sectional detailed view of an actively controlled ACD sealing element disposed within an annular packer system of the ACD annular system, where the annular packer is in an actuated and engaged state.

[0019]FIG. 5A shows a first elevation view of a hybrid MPD integrated riser joint including a hybrid ACD annular sealing system, annular closing system, and flow diverter in accordance with one or more embodiments of the present invention.

[0020]FIG. 5B shows a second elevation view of a hybrid MPD integrated riser joint including a hybrid ACD annular sealing system, annular closing system, and flow diverter in accordance with one or more embodiments of the present invention.

[0021]FIG. 6A shows a cross-sectional view of an MPD integrated riser joint including a hybrid ACD annular sealing system, annular closing system, and flow diverter in accordance with one or more embodiments of the present invention.

[0022]FIG. 6B shows a cross-sectional detailed view of a hybrid rotating sealing element of a hybrid ACD annular sealing system in accordance with one or more embodiments of the present invention.

[0023]FIG. 6C shows a cross-sectional detailed view of a non-rotating ACD sealing element of a hybrid ACD annular sealing system in accordance with one or more embodiments of the present invention.

[0024]FIG. 7A shows a top-facing perspective view of a hybrid rotating sealing element in accordance with one or more embodiments of the present invention.

[0025]FIG. 7B shows a bottom-facing perspective view of a hybrid rotating sealing element in accordance with one or more embodiments of the present invention.

[0026]FIG. 7C shows a front elevation view of a hybrid rotating sealing in accordance with one or more embodiments of the present invention.

[0027]FIG. 7D shows a cross-sectional detailed view of a hybrid rotating sealing element in accordance with one or more embodiments of the present invention.

[0028]FIG. 7E shows a cross-sectional detailed view of a portion of a hybrid rotating sealing element in accordance with one or more embodiments of the present invention.

[0029]FIG. 8A shows a front-facing perspective view of a downward travel locking dog in accordance with one or more embodiments of the present invention.

[0030]FIG. 8B shows a rear-facing perspective view of a downward travel locking dog in accordance with one or more embodiments of the present invention.

[0031]FIG. 8C shows a side elevation view of a downward travel locking dog in accordance with one or more embodiments of the present invention.

[0032]FIG. 8D shows a cross-sectional view of a downward travel locking dog in use in accordance with one or more embodiments of the present invention.

[0033]FIG. 9A shows a detailed view of a hybrid rotating sealing element disposed within an annular packer system with the annular packer in a disengaged state in accordance with one or more embodiments of the present invention.

[0034]FIG. 9B shows a detailed view of a hybrid rotating sealing element disposed within an annular packer system with the annular packer in an engaged state in accordance with one or more embodiments of the present invention.

[0035]FIG. 10A shows a hybrid rotating sealing element disposed above an annular packer system in accordance with one or more embodiments of the present invention.

[0036]FIG. 10B shows a hybrid rotating sealing element disposed within an annular packer system in accordance with one or more embodiments of the present invention.

[0037]FIG. 10C shows a hybrid rotating sealing element disposed below an annular packer system in accordance with one or more embodiments of the present invention.

[0038]FIG. 10D shows a hybrid rotating sealing element disposed above an annular packer system and a hybrid rotating sealing element disposed below the annular packer system in accordance with one or more embodiments of the present invention.

[0039]FIG. 10E shows a hybrid rotating sealing element disposed above an annular packer system and an actively controlled non-rotating ACD sealing element disposed within the annular packer system in accordance with one or more embodiments of the present invention.

[0040]FIG. 10F shows an actively controlled non-rotating ACD sealing element disposed within a annular packer system and a hybrid rotating sealing element disposed below the annular packer system in accordance with one or more embodiments of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

[0041]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. For the purposes of this disclosure, upper or up hole refer to portions of apparatus that are disposed above, or closer to the surface, than lower or downhole portions of the same or other apparatus.

[0042]In onshore applications, an RCD-type annular sealing system is commonly used and is disposed just above the BOP and below the rig floor. An RCD-type annular sealing system typically includes a retrievable seal assembly that is disposed within a housing with ports to divert fluids from the annulus. The housing includes a central bore that is aligned with the central bore of the BOP and has a bore diameter that is greater than or equal to that of the BOP. The retrievable seal assembly is inserted into the central bore of the RCD housing and held in place by one or more locking mechanisms. The retrievable seal assembly typically features a bearing assembly with a smaller central bore through which drill pipe and drill pipe tool joints may pass, a static Outer Diameter (“OD”) seal which blocks the flow of fluid around the bearing assembly, and one or more passive seal elements which flex to create an interference fit with the drill string. Notably, the central bore of the passive sealing elements must be smaller than the OD of the drill string at its smallest point in order to function as intended.

[0043]The passive sealing element stretches to conform to the shape of the drill string in the element and block the flow of fluid through the smaller central bore of the bearing assembly. The retrievable seal assembly has a rotating inner portion and a static outer portion which does not move relative to the housing while the seal assembly is installed. One or more rotary seals are used to seal between the static and rotating portions of the bearing assembly. The passive sealing element conforms to the drill pipe creating a seal, flexing as axial movement causes the OD of the drill string in the element to change. The rotating portion of the seal assembly allows the passive sealing element to rotate with the drill string to reduce wear. This arrangement creates an annular seal that blocks the upward flow of drilling fluid which is diverted from the housing through ports disposed below the retrievable sealing assembly, thereby permitting the application of surface back pressure. One of the drawbacks of using an RCD-type annular sealing system is that a failure of the OD static seals, the passive sealing element, or the rotary seals requires replacement of the entire retrievable seal assembly and depressurization of the wellbore. Another drawback is that there has been no reliable method of determining the remaining life of the passive sealing element or the seal assembly. Notwithstanding, due to its compact design, RCD-type annular sealing systems remain a popular solution for drilling rigs with limited clearance under the rig floor, as is typically the case with land rigs, offshore jack up rigs, and some offshore platform rigs.

[0044]While deepwater drilling has much in common with onshore and shallow water drilling, drilling in deepwater presents a unique set of challenges that limit the effectiveness of RCD-type annular sealing systems. The presence of unconsolidated or uncompacted sediments in deepwater drives the need for additional casing strings increasing the Inner Diameter (“ID”) required of the subsea BOP (“SSBOP”) and the marine riser. Larger diameter hole sections require higher flow rates and larger pipe with better hydraulic characteristics to maintain suitable hole cleaning conditions. Larger pipe uses larger tool joints which require a greater pass-through ID in a bearing assembly, resulting in higher rotary seal velocities and faster wear. When used, the placement of a deepwater RCD-type annular sealing system is typically 100 feet or more below the rig floor. The rig crew must take great care to protect the static OD seals and sealing surfaces when running and pulling the seal assembly, complicating the process, and requiring additional protective measures that take rig time and increase operating costs.

[0045]In recognition of the shortcomings of conventional RCD-type annular sealing systems, National Oilwell Varco, L.P. offers a commercial ACD annular sealing system that addresses the drawbacks of passive RCD-type annular sealing systems in deepwater applications. The ACD annular sealing system allows for the use of non-rotating and actively controlled sealing elements. Unlike the rotating passive sealing element of an RCD-type annular sealing system, actively controlled sealing elements are not designed to be nominally in sealing engagement with the drill string and must be actuated to form sealing engagement on the drill string and continuously actuated to maintain the sealing engagement. The design of the ACD annular sealing system enables the control system to alert the rig crew when an actively controlled sealing element approaches or reaches the end of its design life prior to the loss of wellbore pressure.

[0046]FIG. 1 shows a schematic of a closed-loop hydraulic drilling system 100 for drilling an offshore subterranean wellbore 105. In offshore applications, a floating vessel (not shown), such as, for example, a semi-submersible, drillship, drill barge, or other floating rig or platform may be disposed over a body of water (not shown) to facilitate drilling and other operations. Marine riser system 200 provides fluid communication between the floating vessel (not shown) and components disposed on the seafloor (not shown), including SSBOP 110 that is in fluid communication with the wellhead (not shown) of wellbore 105. Upper portion 205 of marine riser 200 typically includes one or more of rig diverter 215, ball joint 220, telescopic joint 225, and termination joint 230, where telescopic joint 225 articulates to accommodate the heaving motion of the body of water (not shown) in which the drilling rig (not shown) is situated. In below-tension-ring configurations of MPD, an MPD riser joint 300 is disposed below telescopic joint 225.

[0047]MPD riser joint 300 provides fluid communication between upper portion 205 and lower portion 210 of marine riser 200. Lower portion 210 of marine riser 200 provides fluid communication with wellbore 105 by way of SSBOP 110 that is typically disposed above the wellhead (not shown) of wellbore 105. From the drilling rig (not shown), drill string 115 is disposed through the central lumen of upper portion 205 of marine riser 200, MPD riser joint 300, lower portion 210 of marine riser 200, SSBOP 110, and into wellbore 105. The distal end of drill string 115 includes a bottomhole assembly including drill bit 117 for drilling wellbore 105. MPD riser joint 300 is typically assembled onshore and delivered to the drilling rig (not shown) as an integrated joint for deployment. MPD riser joint 300 typically includes annular sealing system 400 disposed above, and in fluid communication with, annular closing system 305. Annular closing system 305 is disposed above, and in fluid communication with, flow diverter 310. Flow diverter 310 is disposed above, and in fluid communication with, lower portion 210 of marine riser 200.

[0048]In the description that follows, annular sealing system 400 may be National Oilwell Varco's commercial ACD annular sealing system that seals annulus 120 surrounding drill string 115, creating an annular seal on the wellbore 105. Notwithstanding, one of ordinary skill in the art will appreciate that the discussion applies with equal force to other annular sealing systems. ACD annular sealing system 400 is purpose built for deepwater use and may be offered as a riser joint that integrates with the riser string below the termination joint 230. Annular sealing system 400 uses one or more independent, retrievable, and actively controlled sealing elements (not shown) that are controlled by control system 1000 disposed on the surface of the drilling rig (not shown). Annular closing system 305 typically serves as a redundant annular seal that may be engaged when annular sealing system 400, or components thereof, are being installed, serviced, removed, or otherwise disengaged. Flow diverter 310 diverts returning fluids from annulus 120, below the annular seal established by annular sealing system 400, to the drilling rig (not shown). Flow diverter 310 is in fluid communication with distribution manifold 125 that is in fluid communication with one or more choke valves of MPD choke manifold 130, disposed on the surface of the drilling rig (not shown). MPD choke manifold 130 is in fluid communication with one or more of mud-gas separator 135, shale shaker 140, and/or other fluids processing system (not shown) that receive returning fluids (not shown) that are recycled for reuse. The processed fluids (not shown) may be diverted to active mud system 145 that sources drilling fluids for one or more mud pumps 150. During drilling operations, the one or more mud pumps 150 may controllably inject drilling fluids (not shown) into an interior passageway (not shown) of drill string 115 for operative use.

[0049]During conventional drilling operations, control system 1000 may receive pressure and other downhole data in approximate or near real-time. For the purposes of this disclosure, near real-time means data is received very nearly when measured, delayed only by the act of measurement, calculation, and/or transmission but within a timeframe that makes the receipt of the data timely for decision making. Control system 1000 may control the flow rate of mud pumps 150, thereby controlling the injection rate of fluids downhole. In addition, control system 1000 may command one or more choke valves of MPD choke manifold 130 to a desired choke aperture setting, thereby controlling the flow rate and the application of surface back pressure.

[0050]The pressure tight seal on annulus 120 provided by annular sealing system 400 allows for the control of wellbore pressure by manipulation of the choke aperture of one or more choke valves of MPD choke manifold 130 on the surface and the corresponding application of surface back pressure. The choke aperture of MPD choke manifold 130 corresponds to an amount, typically represented as a percentage, that MPD choke manifold 130 is open and capable of flowing. For example, each choke valve of MPD choke manifold 130 may be fully opened, fully closed, or somewhere in between with a plurality of intermediate states that refer to some degree of openness. If the choke operator wishes to increase wellbore 105 pressure, the choke aperture of MPD choke manifold 130 may be reduced to further restrict fluid flow and apply additional surface back pressure. Similarly, if the choke operator wishes to decrease wellbore 105 pressure, the choke aperture of MPD choke manifold 130 may be increased to increase fluid flow and reduce the amount of applied surface back pressure. As such, an important function of MPD riser joint 300 is the creation of the annular seal that facilitates management of wellbore pressure through manipulation of the choke aperture of MPD choke manifold 130. In this way, wellbore pressure may be managed by manipulating the flow rates of mud pumps 150 and the application of surface back pressure by manipulation of the choke aperture of MPD choke manifold 130.

[0051]FIG. 2 shows an integrated MPD riser joint 300 including annular sealing system 400, annular closing system 305, and flow diverter 310. Annular sealing system 400 is disposed below the bottom distal end of the outer barrel (not shown) of the telescopic joint (not shown). Annular closing system 305 is disposed directly below annular sealing system 400 and provides a redundant seal. Flow diverter 310 is disposed directly below annular closing system 305 and diverts fluids (not shown) from below the annular seal to the surface (not shown). Annular sealing system 400 seals the annulus (not shown) surrounding the drill string (not shown) such that the annulus (not shown) is encapsulated and not exposed to the atmosphere. Annular sealing system 400 includes upper annular packer system 500a and lower annular packer system 500b, each of which are independently capable of sealing the annulus (not shown) surrounding the drill string (not shown). The redundant combination of annular sealing system 400 and annular closing system 305 further enables the drilling rig (not shown) to maintain wellbore pressure during contingencies. For example, when an actively controlled sealing element (not shown) of annular sealing system 400 requires replacement while the marine riser (not shown) is pressurized, such as, for example, during hole sections in between bit runs, annular closing system 305 may be engaged to maintain annular pressure while the actively controlled sealing elements (not shown) are disengaged and annular sealing system 400 is taken offline.

[0052]FIG. 3A shows a cross-sectional perspective view of an actively controlled non-rotating ACD sealing element 600 of an annular sealing system 400. Actively controlled non-rotating ACD sealing element 600 includes upper metallic end cap 610a, a substantially cylindrical-shaped wear-resistant seal insert 615 co-molded with buffer material 620, and lower metallic end cap 610b. In the disengaged state, actively controlled ACD sealing element 600 includes a central lumen 625 having an ID larger than the OD of the body section of drill pipe (not shown) or tool joints or external upsets (not shown) disposed therethrough and, when actuated and maintained in the engaged state, is configured to squeeze to form an interference fit that creates the annular seal (not shown). However, in contrast to a conventional passive sealing element of an RCD-type annular sealing system that rotates with the drill string (not shown), actively controlled non-rotating ACD sealing element 600 of annular sealing system 400 does not rotate with the drill string (not shown). When actively controlled non-rotating ACD sealing element 600 is engaged, wear-resistant seal insert 615 flexes and makes contact with the drill string (not shown) and provides critical wear resistance as the drill string (not shown) rotates. Buffer material 620 supports wear-resistant seal insert 615 and provides a limited secondary seal in the event seal insert 615 is worn. However, when seal insert 615 is worn, as discussed in more detail herein, buffer material 620 tends to wear very quickly with rotation of the drill string (not shown). Wear-resistant seal insert 615 includes a honeycomb, or other matrix pattern, that effectively reduces the stiffness of the matrix and increases the surface area of the matrix for bonding with buffer material 620.

[0053]Continuing, FIG. 3B shows a cross-sectional elevation view of actively controlled non-rotating ACD sealing element 600 of annular sealing system 400. Wear-resistant seal insert 615 is typically composed of polytetrafluoroethylene (“PTFE”), ultra-high molecular weight polyethylene, or other polymer-based material that resists wear, erosion, and abrasion. The polymer is milled from a solid polymer billet to achieve the correct dimension and additional windows are milled radially through the wall of seal insert 615. During the co-molding process, upper metallic end cap 610a is attached to the top distal end of seal insert 615 and lower metallic end cap 610b is attached to the bottom distal end of seal insert 615. The insert 615 with end caps 610a, 610b attached are secured in a shaped mold and a liquid elastomer is poured into the mold (not shown), filing in the void space of the insert windows and void spaces between the insert 615, end caps 610a, 610b, and the mold (not shown). The elastomer cures in the mold (not shown), retaining the shape of the mold (not shown) once the mold (not shown) is removed. This elastomer buffer material 620 is typically composed of polyurethane, nitrile, acrylonitrile butadiene rubber (“NBR”), hydrogenated acrylonitrile butadiene rubber (“HNBR”), or other elastomer material. Notwithstanding, the material composition of seal insert 615 and buffer material 620 may vary based on an application or design.

[0054]FIG. 4A shows a cross-sectional detailed view of actively controlled non-rotating ACD sealing 600 element disposed within annular packer system 500 of ACD annular sealing system 400, where annular packer 505 is in an unactuated and disengaged state. Annular packer system 500 includes a piston-actuated 515 annular packer 505 disposed within arcuate housing 520. Annular packer 505 is composed of an elastomer or rubber body with a plurality of fingers, or protrusions, 510 that are configured to travel within arcuate housing 520 when piston 515 is actuated. Actively controlled non-rotating ACD sealing element 600 includes a central lumen 625 through which drill string 115, or portions thereof, may pass therethrough.

[0055]Continuing, FIG. 4B shows a cross-sectional detailed view of actively controlled non-rotating ACD sealing element 600 disposed within an annular packer system 500 of the ACD annular sealing system 400, where the annular packer 505 is in an actuated and engaged state. Actively controlled non-rotating ACD sealing element 600 is not normally in sealing engagement with drill string 115 disposed within and is forced into sealing engagement only when actuated by an actuation mechanism and that actuation must be continuously applied to maintain sealing engagement. Actively controlled non-rotating ACD sealing element 600 must be engaged by spherical annular packer 505 that, when actuated, travels within arcuate hosing 520 such that annular packer 505 comes into contact with and squeezes a middle portion of actively controlled non-rotating ACD sealing element 600, such that actuated non-rotating ACD sealing element 600 forms an interference fit with drill string 115 disposed therethrough. Annular packer 505 resists deformation such that the application of a lower hydraulic closing pressure causes the ID of the central bore of annular packer 505 to constrict to a lesser degree while a higher hydraulic closing pressure causes the ID of the central bore of annular packer 505 to constrict to a greater degree. From a fully relaxed state, increasing the hydraulic closing pressure acting on piston 515 causes annular packer 505 to deform such that annular packer 505 material in the central bore makes contact with the OD of the non-rotating ACD sealing element 600. Continued application of closing pressure increasingly deforms annular packer 505 causing the non-rotating ACD sealing element 600 to deform into a somewhat hourglass shape. The externally applied force causes the seal insert (e.g., 615) to deflect radially inward until it contacts the drill string 115, creating the annular seal. As such, actively controlled means that non-rotating ACD sealing element 600 is only engaged while actuation is applied, and once actuation is removed, non-rotating ACD sealing element 600 disengages. The amount of closing pressure required to create the annular seal varies by the wall thickness, wellbore pressure, and OD of the tubulars in actively controlled non-rotating ACD sealing element 600.

[0056]For example, when hydraulically actuated, piston 515 travels causing the elastomer or rubber portion of annular packer 505 to travel within arcuate housing 520 such that annular packer 505 and its fingers 510 come into contact with actively controlled non-rotating ACD sealing element 600. When annular packer 505 is sufficiently actuated, actively controlled non-rotating ACD sealing element 600 squeezes on drill string 115, such that wear-resistant seal insert 615 and buffer material 620 come into contact with a circumference of a portion of drill string 115, resulting in a pressure tight interference fit surrounding drill string 115. Whether engaged or not, actively controlled non-rotating ACD sealing element 600 remains stationary while drill string 115 rotates. The extent to which piston 515 is actuated is controlled by the injection of hydraulic power fluid into the actuation chamber (not shown) of piston 515. As such, the amount of closing pressure exerted on actively controlled non-rotating ACD sealing element 600 may be controlled by the injection of hydraulic power fluid into the actuation chamber (not shown) of piston 515. Thus, the drilling rig (not shown) may provide sufficient closing pressure to ensure that actively controlled non-rotating ACD sealing element 600 form an interference fit and therefore pressure tight seal on the annulus (not independently illustrated). However, the amount of closing pressure required to maintain the annular seal may vary as actively controlled non-rotating ACD sealing element 600 wears.

[0057]Conventional ACD annular sealing systems offered by National Oilwell Varco, L.P. are described in, for example, U.S. Pat. Nos. 11,306,550, 11,306,551, 11,332,998, and 11,377,922, all of which are hereby incorporated by reference for all purposes.

[0058]Accordingly, in one or more embodiments of the present invention, a hybrid rotating sealing element and a hybrid annular sealing system enable the mixed use of a hybrid rotating sealing element and actively controlled non-rotating ACD sealing element within a hybrid ACD-type or other packer-based annular sealing system or the exclusive use of hybrid rotating sealing elements.

[0059]FIG. 5A shows a first elevation view of a hybrid MPD integrated riser joint 700 including hybrid ACD annular sealing system 800, hybrid annular closing system 900, and flow diverter 1000 in accordance with one or more embodiments of the present invention.

[0060]Hybrid MPD integrated riser joint 700 may include hybrid ACD annular sealing system 800, hybrid annular closing system 900 disposed directly below, and in fluid communication with, hybrid ACD annular sealing system 800, and flow diverter 1000 disposed directly below, and in fluid communication with, annular closing system 900. Hybrid MPD integrated riser joint 700 includes a central lumen that extends from distal end to distal end to receive drill pipe, tubulars, or tools (not shown) therethrough. Similar to conventional MPD integrated riser joints (e.g., 300 of FIG. 2), hybrid MPD integrated riser joint 700 may be disposed below a bottom distal end of the outer barrel (not shown) of the telescopic joint or termination joint (e.g., 225 or 230 of FIG. 1) of the marine riser system (e.g., 200 of FIG. 1) in below-tension-ring MPD configurations.

[0061]Hybrid ACD annular sealing system 800 may controllably seal the annulus surrounding drill pipe, tubulars, or tools (not shown) disposed therethrough during drilling operations, while hybrid annular closing system 900 may be disengaged. However, during connection and maintenance operations, hybrid annular closing system 900 may be engaged to seal the annulus surrounding drill pipe, tubulars, or tools (not shown) disposed therethrough, while hybrid ACD annular sealing system 800 may be disengaged. Flow diverter 1000 may include a plurality of goosenecks 1005 that may be used to direct fluids from below the annular seal to the MPD choke manifold (e.g., 130 of FIG. 1) typically disposed on the platform of the floating rig (not shown), that is in fluid communication with a mud-gas separator (e.g., 135 of FIG. 1) and other fluids processing systems (e.g., shale shakers 140, active mud system 145 of FIG. 1) disposed on the surface. The pressure tight seal on the annulus surrounding drill pipe, tubulars, and tools (not shown) provided by hybrid ACD annular sealing system 800 allows for the precise control of wellbore pressure by manipulation of the choke settings of the MPD choke manifold (e.g., 130 of FIG. 1) and the corresponding application of surface backpressure. Advantageously, hybrid MPD integrated riser joint 700 may use any combination of one or more hybrid rotating sealing elements (e.g., 1100) and/or or one or more actively controlled non-rotating ACD sealing elements (e.g., 600) in hybrid ACD annular sealing system 800 or hybrid annular closing system 900. This enables, for the first time, the ability to create an annular seal on drill pipe, tubulars, or tools (not shown) with a rotating sealing element and/or a non-rotating sealing element within the same riser joint. Hybrid MPD integrated riser joint 700 may be used in place of a conventional MPD integrated riser joint (e.g., 300 of FIG. 1) as part of a closed-loop hydraulic drilling system (e.g., 100 of FIG. 1) and thereby enable the use of one or more hybrid rotating sealing elements (e.g., 1100) in an actively controlled ACD-type annular sealing system.

[0062]Continuing, FIG. 5B shows a second elevation view of hybrid MPD integrated riser joint 700 including hybrid ACD annular sealing system 800, hybrid annular closing system 900, and flow diverter 1000 in accordance with one or more embodiments of the present invention.

[0063]Hyrid ACD annular sealing system 800 may include an upper connection end 805 that includes an upper flange 810, an upper tubular portion 815 in fluid communication with upper flange 810, and an upper plurality of downward travel locking dogs 820 disposed about upper tubular portion 815. Hybrid ACD annular sealing system 800 may further include an upper annular packer 500a comprising an upper arcuate housing 520, an upper annular packer (not shown) comprising a upper plurality of protrusions (not shown) disposed within the upper arcuate housing 520, and a central lumen disposed through upper annular packer 500a. Hybrid ACD annular sealing system 800 may further include an intermediate tubular portion 815 disposed below upper annular packer 500a that may include an upper intermediate plurality of downward travel locking dogs 820 disposed about intermediate tubular portion 815 below upper annular packer 500a and a lower intermediate plurality of downward travel locking dogs 820 disposed about intermediate tubular portion 815 above lower annular packer 500b. Hybrid ACD annular sealing system 800 may further include a lower connection end 825 that includes a lower flange 810, a lower tubular portion 815 disposed below lower annular packer 500b, and a lower plurality of downward travel locking dogs 820 disposed below lower annular packer 500b. As discussed in more detail herein, an upper hydraulically actuated piston (not independently illustrated) may controllably cause an upper annular packer (not shown) to travel within upper arcuate housing 520 of upper annular packer 500a, narrowing the central lumen therethrough to form sealing engagement with a hybrid rotating sealing element (e.g., 1100) or cause an actively controlled non-rotating ACD sealing element (e.g., 600) to flex to form sealing engagement with drill pipe, tubulars, or tools (not shown) disposed through the central lumen. Similarly, a lower hydraulically actuated piston (not independently illustrated) may controllably cause a lower annular packer (not shown) to travel within lower arcuate housing 820 of lower annular packer 500b narrowing the central lumen therethrough to form sealing engagement with a hybrid rotating sealing element (e.g., 1100) or cause an actively controlled non-rotating ACD sealing element (e.g., 600) to flex to form sealing engagement with drill pipe, tubulars, or tools (not shown) disposed through the central lumen.

[0064]While hybrid annular closing system 900 is shown as part of hybrid MPD integrated riser joint 700, hybrid annular closing system 900 may include an upper connection end (e.g., 810) that includes an upper flange (e.g., 810), an upper tubular portion 815 in fluid communication with upper flange 810, and an upper plurality of downward travel locking dogs 820 disposed about upper tubular portion 815. Hybrid annular closing system 900 may further include an annular packer 500c comprising an arcuate housing 520, an annular packer (not shown) comprising a plurality of protrusions (not shown) disposed within arcuate housing 520, and a central lumen disposed through annular packer 500c. Hybrid annular closing system 900 may further include a lower connection end (e.g., 825) that includes a lower flange (e.g., 810), a lower tubular portion 815 disposed below annular packer 500c, and a lower plurality of downward travel locking dogs 820 disposed below annular packer 500c. As discussed in more detail herein, a hydraulically actuated piston (not independently illustrated) may controllably cause an annular packer (not shown) to travel within arcuate housing 520 of annular packer 500c, narrowing the central lumen therethrough to form sealing engagement with a hybrid rotating sealing element (e.g., 1100) or cause an actively controlled non-rotating ACD sealing element (e.g., 600) to flex to form sealing engagement with drill pipe, tubulars, or tools (not shown) disposed through the central lumen.

[0065]FIG. 6A shows a cross-sectional view of MPD integrated riser joint 700 including hybrid ACD annular sealing system 800, hybrid annular closing system 900, and flow diverter 1000 in accordance with one or more embodiments of the present invention. In one or more embodiments of the present invention, hybrid ACD annular sealing system 800 may include a hybrid rotating sealing element 1100 and an actively controlled non-rotating ACD sealing element 600. In certain embodiments, hybrid rotating sealing element 1100 and actively controlled non-rotating ACD sealing element 600 may be disposed on a single mandrel 850. In still other embodiments, hybrid rotating sealing element 1100 and actively controlled non-rotating ACD sealing element 600 may be disposed on independent mandrels (not shown). In certain embodiments, hybrid rotating sealing element 1100 may be disposed above actively controlled non-rotating ACD sealing element 600. In other embodiments, hybrid rotating sealing element 1100 may be disposed below actively controlled non-rotating ACD sealing element 600 (not shown). In one or more embodiments of the present invention, hybrid annular sealing system 800 may include an upper hybrid rotating sealing element 1100 and a lower hybrid rotating sealing element (not shown, e.g., 1100 in place of 600) disposed within hybrid ACD annular sealing system 800. In certain embodiments, upper hybrid rotating sealing element 1100 and lower hybrid rotating sealing element (now shown) may be disposed on a single mandrel (e.g., 850). In other embodiments, upper hybrid rotating sealing element 1100 and lower hybrid rotating sealing element (now shown) may be disposed on a single mandrel (e.g., 850) may be disposed on independent mandrels.

[0066]One of ordinary skill in the art having the benefit of this disclosure will appreciate that the selection of sealing elements may vary based on an application or design or other factors in accordance with one or more embodiments of the present invention.

[0067]Continuing, FIG. 6B shows a cross-sectional detailed view of hybrid rotating sealing element 1100 of hybrid ACD annular sealing system 800 in accordance with one or more embodiments of the present invention. As previously discussed, hybrid rotating sealing element 1100 may be run in on an independent mandrel (not shown) or mandrel 850 on which multiple sealing elements (e.g., 1100 and 600 of FIG. 6A) are disposed. When running in hybrid rotating sealing element 1100, a plurality of downward travel locking dogs 820 disposed below upper annular packer system 500a may be hydraulically actuated to create a landing profile for mandrel 850. Mandrel 850 may include a receiver for an angled face (e.g., 840) and a recessed flat surface (e.g., 845) with room for downward travel before contact with each locking dog 820. Once landed, a plurality of downward travel locking dogs 820 disposed above upper annular packer system 500a may be hydraulically actuated to secure hybrid rotating sealing element 1100 in place. Hybrid rotating sealing element 1100 may include an intra-overshot-pipe assembly 1165 on a top distal end of hybrid rotating sealing element 1100 that includes another landing profile. Once hybrid rotating sealing element 1100 is secured in place, upper annular packer 505 of upper annular packer 500a may be actuated to form sealing engagement with an external sealing feature 1110 of hybrid rotating sealing element 1100. External sealing feature 1110 may include a surface shape and material composition that is similar to buffer material (e.g., 620) of an actively controlled non-rotating ACD sealing element (e.g., 600). In one or more embodiments of the present invention, external sealing feature 1110 may be composed of polyurethane, nitrile, NBR, HNBR, or other elastomer material. This further enhances the sealing capability of hybrid rotating sealing element 1100 when disposed in hybrid ACD annular sealing system 800 by preventing fluids from leaking through upper annular packer 505 of upper annular packer system 500a.

[0068]Drill pipe, tubulars, and tools (not shown) may be disposed through a central lumen of internal mandrel 1115 of hybrid rotating sealing element 1100. A first interference-fit sealing element 1160 of hybrid rotating sealing element 1100 may form sealing engagement with the drill pipe, tubulars, and tools (not shown) disposed therethrough. While the primary sealing capabilities of hybrid rotating sealing element 1100 are discussed in more detail herein, hybrid rotating sealing element 1100 may include an intra-overshot-pipe assembly 1165 that may be removably attached to a top distal end of hybrid rotating sealing element 1100. Intra-overshot-pipe assembly 1165 may include a second interference-fit sealing element 1170 and a landing profile for a downward travel locking dogs 820. In this way, first interference-fit sealing element 1160, internal mandrel 1115, and second interference-fit sealing element 1170 may rotate with the rotation of drill pipe, tubulars, or tools (not shown) disposed therethrough. First interference-fit sealing element 1160 may have a first seal lumen (not independently illustrated) having a first seal inner aperture (not independently illustrated) slightly smaller than an outer diameter of drill pipe, tubulars, or tools (not shown) and second interference-fit sealing element 1170 may have a second seal lumen (not independently illustrated) having a second seal inner aperture (not independently illustrated) slightly smaller than an outer diameter of drill pipe, tubulars, or tools (not shown). In one or more embodiments of the present invention, first interference-fit sealing element 1160 and second sealing element 1170 may be composed of natural rubber, nitrile butadiene rubber, hydrogenated nitrile butadiene rubber, polyurethane, elastomeric material, or combinations thereof.

[0069]Continuing, FIG. 6C shows a cross-sectional detailed view of a non-rotating ACD sealing element 600 of hybrid ACD annular sealing system 800 in accordance with one or more embodiments of the present invention. As previously discussed, non-rotating ACD sealing element 600 may be run in on an independent mandrel (not shown) or mandrel 850 on which multiple sealing elements (e.g., 1100 and 600 of FIG. 6A) are disposed. When running in non-rotating ACD sealing element 600, a plurality of downward travel locking dogs 820 disposed below lower annular packer system 500b may be hydraulically actuated to create a landing profile for mandrel 850. Mandrel 850 may include a receiver for an angled face (e.g., 840) and a recessed flat surface (e.g., 845) with room for downward travel before contact with each locking dog 820. Once landed, a plurality of downward travel locking dogs 820 disposed above upper annular packer system 500b may be hydraulically actuated to secure hybrid rotating sealing element 1100 in place. The operation of actively controlled non-rotating ACD sealing element 600 is described above with reference to FIG. 4A and FIG. 4B.

[0070]FIG. 7A shows a top-facing perspective view of an embodiment of a hybrid rotating sealing element 1100 in accordance with one or more embodiments of the present invention. In this exterior view, various features are denoted by their relative positions. Hybrid rotating sealing element 1100 may include an intra-overshot-pipe assembly 1165, an upper seal carrier 1135, an external sealing feature 1110, a lower seal carrier 1135 and a bottom distal end that includes, but does not show in this view, a first interference-fit sealing element (e.g., 1160). Continuing, FIG. 7B shows a bottom-facing perspective view of hybrid rotating sealing element 1100 in accordance with one or more embodiments of the present invention. Continuing, FIG. 7C shows a front elevation view of hybrid rotating sealing element 1110 in accordance with one or more embodiments of the present invention. Intra-overshot-pipe assembly 1165 may include a landing profile 1175 for downward travel locking dogs (e.g., 820).

[0071]Continuing, FIG. 7D shows a cross-sectional detailed view of hybrid rotating sealing element 1100 in accordance with one or more embodiments of the present invention. Hybrid rotating sealing element 1100 may include seal and bearing housing 1105, a rotating internal mandrel 1115 disposed within an inner aperture of seal and bearing housing 1105, a first interference-fit sealing element 1160 attached to a bottom distal end of internal mandrel 1115, a plurality of tapered thrust-bearings 1120 indirectly mounted to seal and bearing housing 1105 to facilitate rotation of internal mandrel 1115, a preload spacer 1130 disposed between top and bottom tapered-thrust bearings 1120, and a plurality of jam nuts 1125 to adjust a preload of the tapered-thrust bearings 1120. The plurality of tapered-thrust bearings 1120 may be indirectly mounted to seal and bearing housing 1105 at an offset angle to increase radial stability and prevent wear out from reciprocation of drill pipe, tubulars, or tools (not shown) disposed therethrough. Central lumen 1180 extends from distal end to distal end of hybrid rotating sealing element 1100. The plurality of jam nuts 1125 may be threaded such that they maintain preload with rotation of the drill pipe, tubulars, or tools (not shown).

[0072]Intra-overshot-pipe assembly 1165 may include a landing profile 1175 for receiving a plurality of downward travel locking dogs (e.g., 820) to controllably secure hybrid rotating sealing element 1100 within an annular packer system (e.g., 500). to rotating control device 100. One or more static sealing elements 1155 may be disposed about an outer surface of hybrid rotating sealing element 1100 to provide a static seal between hybrid rotating sealing element 1100 and the annular packer system (e.g., 500) in which it may be disposed. Lower seal carrier 1135 may include a plurality of dynamic sealing elements 1150 that contact rotating internal mandrel 1115 and a plurality of static sealing elements 1155 that contact seal and bearing housing 1105. Upper seal carrier 1135 may also include a plurality of dynamic sealing elements 1150 and a plurality of static sealing elements 1155. First interference-fit sealing element 1160, internal mandrel 1115, and optional second interference-fit sealing element 1170 may rotate with the drill pipe, tubulars, or tools (not shown). The first 1160 and the second 1170 interference-fit sealing element may be composed of natural rubber, nitrile butadiene rubber, hydrogenated nitrile butadiene rubber, polyurethane, elastomeric material, or combinations thereof. First interference-fit sealing element 1160 may include a first seal lumen having a first seal inner aperture slightly smaller than an outer diameter of the drill pipe (not shown) and the second interference-fit sealing element 1170 may include a second seal lumen having a second seal inner aperture slightly smaller than an outer diameter of the drill pipe (not shown). Central lumen 1180 may extend from distal end to distal end of hybrid rotating sealing element 1100. During drilling operations, a drill pipe (not shown) may be disposed through central lumen 1180, whereby a first and a second annular seal may be established, in part, by first interference-fit sealing element 1160 and second interference-fit sealing element 1170. When an annular packer (e.g., 505) of an annular packer system (e.g., 500) is actuated, the annular packer (e.g., 505) forms sealing engagement with external sealing feature 1110 of hybrid rotating sealing element 1100. In this way, external sealing feature 1110 provides an additional seal that prevents leakage between the exterior of hybrid rotating sealing element 1100 and the annular packer system (e.g., 500) in which it may be disposed.

[0073]Continuing, FIG. 7E shows a cross-sectional detailed view of a portion of hybrid rotating sealing element 1100 in accordance with one or more embodiments of the present invention. A plurality of tapered-thrust bearings 1120 may be indirectly mounted at an offset angle to increase radial stability. In certain embodiments, upper tapered-thrust bearings 1120 may be indirectly mounted at an offset angle, θ, in a range between 10 degrees and 40 degrees from a perpendicular line to a longitudinal axis of hybrid rotating sealing element 1100. In other embodiments, upper tapered-thrust bearings 1120 may be indirectly mounted at an offset angle, θ, in a range between 20 degrees and 30 degrees from a perpendicular line to a longitudinal axis of hybrid rotating sealing element 1100. In still other embodiments, upper tapered-thrust bearings 1120 may be indirectly mounted at an offset angle, θ, in a range between 0 degrees and 50 degrees from a perpendicular line to a longitudinal axis of hybrid rotating sealing element 1100. One of ordinary skill in the art will recognize that the positive offset angle of upper tapered-thrust bearings 1120 may vary based on an application or design in accordance with one or more embodiments of the present invention.

[0074]Lower tapered-thrust bearings 1120 may be indirectly mounted at an offset angle, θ, in a range between −10 degrees and −40 degrees from a perpendicular line to a longitudinal axis of hybrid rotating sealing element 1100. In other embodiments, lower tapered-thrust bearings 1120 may be indirectly mounted at an offset angle, θ, in a range between −20 degrees and −30 degrees from a perpendicular line to a longitudinal axis of hybrid rotating sealing element 1100. In still other embodiments, upper tapered-thrust bearings 1120 may be indirectly mounted at an offset angle, −θ, in a range between 0 degrees and −50 degrees from a perpendicular line to a longitudinal axis of hybrid rotating sealing element 1100. One of ordinary skill in the art will recognize that the offset angle of lower tapered-thrust bearings 1120 may vary based on an application or design in accordance with one or more embodiments of the present invention.

[0075]A plurality of jam nuts 1125 may be used to preload the plurality of tapered-thrust bearings 1120, the upper 1120 and lower 1120 of which are separated by a preload spacer 1130. Jam nuts 1125 may be tightened or loosened to adjust a preload on tapered-thrust bearings 1120 and preload spacer 1130. Upper seal carrier 1135, the plurality of jam nuts 1125, and lower seal carrier 1135 may be threaded or otherwise attached such that they maintain preload during rotation of the drill pipe, tubulars, or tools (not shown) disposed therethrough. The plurality of dynamic sealing elements 1150 are disposed in grooves formed on an inner circumferential surface of each respective seal carrier 1135. Over time, these dynamic sealing elements 1150 wear into their respective seal carriers 1135 and become difficult to remove and ultimately replace. Seal carriers 1135 may include a plurality of removable seal carrier trays 1140 to facilitate the quick and easy removal and replacement of dynamic sealing elements 1150 in the field. A plurality of static sealing elements 1155 may be disposed about an outer surface of hybrid rotating sealing element 1100 to provide a static and non-rotating seal between seal between hybrid rotating sealing element 1100 and an annular packer system (e.g., 500) in which it is disposed.

[0076]FIG. 8A shows a front-facing perspective view of downward travel locking dog 820 in accordance with one or more embodiments of the present invention. Downward travel locking dog 820 may include actuation end 825 comprising a hydraulically actuated piston (not shown), housing 830, and an extendable engagement end 835 having on a distal end angled face 840 on a first side and a recessed flat surface 845 on a second side. The hydraulically actuated piston (not shown) may controllably drive engagement end 835 outwards (not shown). Recessed flat surface 845 is recessed to enable downward travel of sealing elements (e.g., 1100 or 600) disposed within an annular packer system (e.g., 500) during engagement and being secured into place. Continuing, FIG. 8B shows a rear-facing perspective view of downward travel locking dog 820 in accordance with one or more embodiments of the present invention. Continuing, FIG. 8C shows a side elevation view of downward travel locking dog 820 in accordance with one or more embodiments of the present invention. Extendable engagement end 835 may, when actuated, extend outwards and angled face 840 and recessed flat surface 845 may be used to secure sealing elements (e.g., 1100 or 600) disposed within an annular packer system (e.g., 500) during engagement and being secured into place. Continuing, FIG. 8D shows a cross-sectional view of downward travel locking dog 820 in use in accordance with one or more embodiments of the present invention. As shown in this view, downward travel locking dog 820 is attached to an exterior of tubular 815. In this example, a hybrid rotating sealing element 1100 is disposed within tubular 815 and downward travel locking dog 820 is shown engaging with hybrid rotating sealing element 1100. As shown in this view, the landing profile of hybrid rotating sealing element 1100 has a complementary shape to that of engagement end 835 of downward travel locking dog 820. As such, engagement end 835 enables downward travel of hybrid rotating sealing element 1100 prior to engagement of angled face 840. In other embodiments (not shown), the orientation of downward travel locking dog 820 may be flipped over such that recessed flat surface 845 is the engaging face.

[0077]FIG. 9A shows a detailed view of hybrid rotating sealing element 1100 disposed within annular packer system 500 with annular packer 505 in a disengaged state in accordance with one or more embodiments of the present invention. Continuing, FIG. 9B shows a detailed view of hybrid rotating sealing element 1100 disposed within annular packer system 500 with annular packer 505 in an engaged state in accordance with one or more embodiments of the present invention.

[0078]Hybrid MPD integrated riser joint 700 as well as hybrid ACD annular sealing system 800, and hybrid annular closing system 900 permit other placements of sealing elements (e.g., 1100 or 600) through the use of various mandrels. For example, FIG. 10A shows hybrid rotating sealing element 1100 disposed above annular packer system 500 in accordance with one or more embodiments of the present invention. Continuing, FIG. 10B shows hybrid rotating sealing element 1100 disposed within annular packer system 500 in accordance with one or more embodiments of the present invention. Continuing, FIG. 10C shows hybrid rotating sealing element 1100 disposed below annular packer system 500 in accordance with one or more embodiments of the present invention. Continuing, FIG. 10D shows hybrid rotating sealing element 1100 disposed above annular packer system 500 and another hybrid rotating sealing element 1100 disposed below annular packer system 500 in accordance with one or more embodiments of the present invention. Continuing, FIG. 10E shows hybrid rotating sealing element 1100 disposed above annular packer system 500 and actively controlled non-rotating ACD sealing element 600 disposed within annular packer system 500 in accordance with one or more embodiments of the present invention. Continuing, FIG. 10F shows actively controlled non-rotating ACD sealing element 600 disposed within annular packer system 500 and hybrid rotating sealing element 1100 disposed below annular packer system 500 in accordance with one or more embodiments of the present invention.

[0079]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 only be limited by the appended claims.