SEAL ASSEMBLY LIFE EXTENSION METHODS

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of PCT/US2024/014938, filed on Feb. 8, 2024, which claims the benefit of, or priority to, U.S. Provisional Patent Application 63/447,967, filed on Feb. 24, 2023, both of which are hereby incorporated by reference in its entirety.

BACKGROUND OF THE INVENTION

In conventional drilling operations, drilling fluid, sometimes referred to as mud, is circulated through the drill string and the wellbore to cool and lubricate the drill bit, remove cuttings from the wellbore, and maintain wellbore stability. The drilling fluid is critical to maintaining primary well control through the application of hydrostatic pressure. As drilling progresses, the drilling rig must regularly stop circulation of the drilling fluid, set the drill string into slips, break the connection between the top drive and the uppermost joint of pipe in a stand and then add another stand of drill pipe to the drill string in a process commonly referred to as making a connection. After the connection is made, the drill string can be used to drill ahead further and extend the depth of the wellbore.

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. However, to drill ahead to extend the depth of the wellbore, the drilling rig must circulate drilling fluid. 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.

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. An overbalanced condition occurs when the pressure in the wellbore is greater than the formation pressure. An underbalanced condition occurs when the pressure in the wellbore is less than the formation pressure. Most drilling occurs under a slight to moderate overbalanced condition. In some cases, the drilling rig risks taking an influx of fluid, commonly referred to as a kick, when the static downhole pressure in the wellbore is less than the pore pressure of the adjacent rock. In other cases, the drilling rig risks causing a wellbore collapse when the static downhole pressure in the wellbore is less than the collapse pressure of the adjacent rock. In still other cases, if the circulating downhole pressure in the wellbore is greater than the fracture pressure of the adjacent rock (e.g., a highly overbalanced condition), the drilling 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. Other complications, similar to those noted above, may arise when tripping pipe in and out of the well.

Alternatively, 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. Drilling returns are diverted from below the annular seal to the surface through the dedicated MPD choke manifold. The MPD choke manifold typically includes a plurality of choke valves that are commanded by a control system to a desired choke aperture. 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. In onshore applications, an RCD-type annular sealing system is commonly used and is disposed just above the blowout preventer (“BOP”) and below the rig floor. An RCD-type annular sealing system typically includes a retrievable seal assembly and 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. 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.

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 drive 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.

In recognition of the shortcomings of 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 affirmatively 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.

Much like passive RCD-type annular sealing systems, the lifespan of an actively controlled sealing element may vary significantly based on the operating conditions in which it is used. Several factors affect the service life of an actively controlled sealing element including, the condition of the drill pipe, rough hard banding (rough areas where metal has been additionally strengthened), and excessive tong marks (sharp edges created by gripping the tool joint) that tend to increase abrasion when a tool joint passes through an actively controlled sealing element. In addition, high speed rotation of drill pipe disposed within the actively controlled sealing element, results in a higher temperature due to increased friction between the rotating drill pipe and non-rotating actively controlled sealing element and is a contributing factor for certain types of wear or damage to the actively controlled sealing element. Finally, high pressure differential across the actively controlled sealing element creates the potential for jetting of fluids across the sealing faces, leading to erosion of the seal material. Actively controlled sealing elements may wear whether closed against a tool joint or the smoother body section of the drill pipe of the tubular drill string. However, actively controlled sealing elements are prone to wear, and damage caused by tool joints transiting through a closed actively controlled sealing element.

SUMMARY OF THE INVENTION

According to one aspect of one or more embodiments of the present invention, a method of operating a plurality of actively controlled sealing elements includes, for each actively controlled sealing element, determining a location of a tool joint or external upset of a tubular drill string relative to the actively controlled sealing element, determining a first condition is met when a body section of the tubular drill string is disposed within the actively controlled sealing element, operating the actively controlled sealing element using a first set of parameters when the first condition is met, determining a second condition is met when the tool joint or external upset of the tubular drill string is disposed within the actively controlled sealing element, operating the actively controlled sealing element using a second set of parameters when the second condition is met, determining a third condition is met when the tool joint or external upset is anticipated to transit the actively controlled sealing element, and operating the actively controlled sealing element using the second set of parameters when the third condition is met and during the transit of the actively controlled sealing element.

According to one aspect of one or more embodiments of the present invention, a method of operating an actively controlled sealing element includes determining a location of a tool joint or external upset of a tubular drill string relative to the actively controlled sealing element, determining a first condition is met when a body section of the tubular drill string is disposed within the actively controlled sealing element, operating the actively controlled sealing element using a first set of parameters when the first condition is met, determining a second condition is met when the tool joint or external upset of the tubular drill string is disposed within the actively controlled sealing element, operating the actively controlled sealing element using a second set of parameters when the second condition is met, determining a third condition is met when the tool joint or external upset is anticipated to transit the actively controlled sealing element, and operating the actively controlled sealing element using the second set of parameters when the third condition is met and during the transit of the actively controlled sealing element.

According to one aspect of one or more embodiments of the present invention, a method of sequentially activating actively controlled sealing elements includes actuating a first actively controlled sealing element into sealing engagement with a tubular drill string, relaxing a second actively controlled sealing element while the first actively controlled sealing element is actuated, determining when the first actively controlled sealing element is consumed to a predetermined extent, actuating the second actively controlled sealing element into sealing engagement with the tubular drill string, and relaxing the first actively controlled sealing element while the second actively controlled sealing element is actuated.

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

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 2 shows an integrated managed pressure drilling riser joint including an annular sealing system, an annular closing system, and a flow diverter.

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

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

FIG. 3C shows a hybrid cross-sectional view of a dual seal sleeve for use as part of an ACD annular sealing system.

FIG. 3D shows a hybrid cross-sectional view of independent seal sleeves for use as part of an ACD annular sealing system.

FIG. 4A shows an elevation view of an ACD annular sealing system.

FIG. 4B shows a hybrid cross-sectional elevation view of the ACD annular sealing system.

FIG. 5A shows a hybrid cross-sectional elevation view of an ACD annular sealing system with a dual seal sleeve operatively positioned within an upper annular packer system and a lower annular packer system of the ACD annular sealing system.

FIG. 5B shows a detailed hybrid cross-sectional elevation view of an upper actively controlled sealing element disposed within the upper annular packer system of the ACD annular sealing system.

FIG. 5C shows a detailed hybrid cross-sectional elevation view of a lower actively controlled sealing element disposed within the lower annular packer system of the ACD annular sealing system.

FIG. 6A shows a cross-sectional detailed view of an actively controlled sealing element disposed within an annular packer system of an ACD annular sealing system, where the annular packer is in a unactuated and disengaged state.

FIG. 6B shows a cross-sectional detailed view of an actively controlled sealing element disposed within an annular packer system of the ACD annular system, where the annular packer is in an actuated and engaged state.

FIG. 7A shows a hybrid cross-sectional view of an actively controlled sealing element of an ACD annular sealing system in an unworn state.

FIG. 7B shows a hybrid cross-sectional view of the actively controlled sealing element of the ACD annular sealing system in a partially worn state.

FIG. 7C shows a hybrid cross-sectional view of the actively controlled sealing element of the ACD annular sealing system in a substantially worn state.

FIG. 7D shows a hybrid cross-sectional view of the actively controlled sealing element of the ACD annular sealing system in a worn state.

FIG. 8A shows a plot of actuation parameters of the actively controlled sealing elements and block height versus time in accordance with one or more embodiments of the present invention.

FIG. 8B shows a plot of actuation parameters of the actively controlled sealing elements and block height versus time with vertical reference lines that traverse the full scale of the y-axis indicate where in the time sequence a tool joint enters a seal sleeve in accordance with one or more embodiments of the present invention.

FIG. 8C shows a plot of actuation parameters of the actively controlled sealing elements and block height versus time where horizontal reference lines that traverse the full scale of the x-axis indicate where on the block height the vertical lines intersect with the block height, in accordance with one or more embodiments of the present invention.

FIG. 9A shows a tool joint starting to transit an upper actively controlled sealing element of an ACD annular sealing system in accordance with one or more embodiments of the present invention.

FIG. 9B shows the tool joint transiting the upper actively controlled sealing element of the ACD annular sealing system in accordance with one or more embodiments of the present invention.

FIG. 9C shows the tool joint transiting out of the upper actively controlled sealing element of the ACD annular sealing system in accordance with one or more embodiments of the present invention.

FIG. 9D shows the tool joint disposed in between the upper actively controlled sealing element and the lower Actively controlled sealing element of the ACD annular sealing system in accordance with one or more embodiments of the present invention.

FIG. 9E shows the tool joint starting to transit the lower actively controlled sealing element of the ACD annular sealing system in accordance with one or more embodiments of the present invention.

FIG. 9F shows the tool joint transiting the lower actively controlled sealing element of the ACD annular sealing system in accordance with one or more embodiments of the present invention.

FIG. 9G shows the tool joint transiting out of the lower actively controlled sealing element of the ACD annular sealing system in accordance with one or more embodiments of the present invention.

FIG. 9H shows the tool joint disposed below the lower actively controlled sealing element of the ACD annular sealing system in accordance with one or more embodiments of the present invention.

FIG. 10 shows a control system for an ACD annular sealing system in accordance with one or more embodiments of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

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 uphole 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.

In one or more embodiments of the present invention, methods of operating one or more actively controlled sealing elements are disclosed that advantageously extend the runtime of the one or more actively controlled sealing elements and reduce the amount of wear induced by a transiting tool joint. In certain embodiments, the activation of two or more independent actively controlled sealing elements are coordinated as a function of the position of tool joints or external upsets in relation to the actively controlled sealing elements. In other embodiments disclosed herein, the activation of two or more independent actively controlled sealing elements are sequenced using a first actively controlled sealing element until the end of its design life and then utilizing a second actively controlled sealing element. In still other embodiments, a single actively controlled sealing element may be variably actuated as a function of the position of tool joints or external upsets in relation to the actively controlled sealing element. Advantageously, runtime of actively controlled sealing elements may be substantially extended improving productivity, operational uptime, reducing operating costs, and reducing maintenance costs.

FIG. 1 shows a schematic of a closed-loop hydraulic drilling system 100 for drilling an offshore subterranean wellbore 102. 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 104 that is in fluid communication with the wellhead (not shown) of wellbore 102. Upper portion 202 of marine riser 200 typically includes one or more of rig diverter 204, ball joint 206, telescopic joint 208, and termination joint 210, where telescopic joint 208 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 integrated MPD riser joint 300 is disposed below telescopic joint 210.

MPD riser joint 300 provides fluid communication between upper portion 202 and lower portion 212 of marine riser 200. Lower portion 212 of marine riser 200 provides fluid communication with wellbore 102 by way of SSBOP 104 that is typically disposed above the wellhead (not shown) of wellbore 102. From the drilling rig (not shown), drill string 106 is disposed through the central lumen of upper portion 202 of marine riser 200, MPD riser joint 300, lower portion 212 of marine riser 200, SSBOP 104, and into wellbore 102. The distal end of drill string 106 includes a bottomhole assembly including drill bit 108 for drilling wellbore 102. 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 302. Annular closing system 302 is disposed above, and in fluid communication with, flow diverter 304. Flow diverter 304 is disposed above, and in fluid communication with, lower portion 212 of marine riser 200.

In the description that follows, annular sealing system 400 may be National Oilwell Varco's commercial ACD annular sealing system that seals annulus 110 surrounding drill string 106, creating an annular seal on the wellbore 102. Notwithstanding, one of ordinary skill in the art will appreciate that the discussion applies with equal force to other annular sealing systems. The 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 210. 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 302 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 304 diverts returning fluids from annulus 110, below the annular seal established by annular sealing system 400, to the drilling rig (not shown). Flow diverter 304 is in fluid communication with distribution manifold 112 that is in fluid communication with one or more choke valves of MPD choke manifold 114, disposed on the surface of the drilling rig (not shown). MPD choke manifold 114 is in fluid communication with one or more of mud-gas separator 116, shale shaker 118, 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 120 that sources drilling fluids for one or more mud pumps 122. During drilling operations, the one or more mud pumps 122 may controllably inject drilling fluids (not shown) into an interior passageway (not shown) of drill string 106 for operative use.

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 122, thereby controlling the injection rate of fluids downhole. In addition, control system 1000 may command one or more choke valves of MPD choke manifold 114 to a desired choke aperture setting, thereby controlling the flow rate and the application of surface back pressure.

The pressure tight seal on annulus 110 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 114 on the surface and the corresponding application of surface back pressure. The choke aperture of MPD choke manifold 114 corresponds to an amount, typically represented as a percentage, that MPD choke manifold 114 is open and capable of flowing. For example, each choke valve of MPD choke manifold 114 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 102 pressure, the choke aperture of MPD choke manifold 114 may be reduced to further restrict fluid flow and apply additional surface back pressure. Similarly, if the choke operator wishes to decrease wellbore 102 pressure, the choke aperture of MPD choke manifold 114 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 114. In this way, wellbore pressure may be managed by manipulating the flow rates of mud pumps 122 and the application of surface back pressure by manipulation of the choke aperture of MPD choke manifold 114.

FIG. 2 shows an integrated MPD riser joint 300 including annular sealing system 400, annular closing system 302, and flow diverter 306. 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 302 is disposed directly below annular sealing system 400 and provides a redundant seal. Flow diverter 306 is disposed directly below annular closing system 302 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 302 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 302 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.

FIG. 3A shows a cross-sectional perspective view of an actively controlled sealing element 600 of an annular sealing system 400. Actively controlled sealing element 600 includes upper metallic end cap 610a, a substantially cylindrical-shaped wear-resistant seal insert 620 co-molded with buffer material 630, and lower metallic end cap 610b. In the disengaged state, actively controlled sealing element 600 includes a central lumen 640 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 sealing element 600 of annular sealing system 400 does not rotate with the drill string (not shown). When actively controlled sealing element 600 is engaged, wear-resistant seal insert 620 flexes and makes contact with the drill string (not shown) and provides critical wear resistance as the drill string (not shown) rotates. Buffer material 630 supports wear-resistant seal insert 620 and provides a limited secondary seal in the event seal insert 620 is worn. However, when seal insert 620 is worn, as discussed in more detail herein, buffer material 630 tends to wear very quickly with rotation of the drill string (not shown). Wear-resistant seal insert 620 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 630.

Continuing, FIG. 3B shows a cross-sectional elevation view of actively controlled sealing element 600 of annular sealing system 400. Wear-resistant seal insert 620 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 620. During the co-molding process, upper metallic end cap 610a is attached to the top distal end of seal insert 620 and lower metallic end cap 610b is attached to the bottom distal end of seal insert 620. The insert 620 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 620, 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 630 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 620 and buffer material 630 may vary based on an application or design.

Continuing, FIG. 3C shows a hybrid cross-sectional view of a dual seal sleeve 700 for use as part of an annular sealing system (e.g., 400). In some applications, the annular sealing system (e.g., 400) may use a dual seal sleeve 700 including upper actively controlled sealing element 600a and lower actively controlled sealing element 600b disposed on mandrel 702. Dual seal sleeve 700 may include upper end piece 704, upper actively controlled sealing element 600a, mandrel 702, vented intermediate spacer 706, lower actively controlled sealing element 600b, and lower end piece 708. Dual seal sleeve 700 includes a central lumen 710 that extends through the longitudinal length of sleeve 700 through which the drill string (not shown) may be disposed. When upper actively controlled sealing element 600a and lower actively controlled sealing element 600b are engaged (not shown), a cavity (not independently illustrated) may be formed between them that encompasses the inner area of vented intermediate spacer 706. When drilling ahead, the pressure of the cavity (not independently illustrated) may be maintained just above wellbore pressure by injecting a lubrication fluid (not shown) that may be comprised of, for example, active drilling mud, into the cavity (not independently illustrated) to ensure that wellbore fluids (not shown) do not leak through. The hydraulic piston actuated closing pressures (not shown) of the upper annular packer system (e.g., 500a) and the lower annular packer system (e.g., 500b) of the annular sealing system (e.g., 400) are configured to engage upper actively controlled sealing element 600a and lower actively controlled sealing element 600b respectively and may be independently adjusted to maintain the annular seal (not shown). Lubrication fluid (not shown) may be injected into the lubrication chamber (not independently illustrated) to a desired pressure, typically somewhat higher than the wellbore pressure. The lubrication fluid (not shown) cools and lubricates upper actively controlled sealing element 600a and lower actively controlled sealing element 600b. Because of the rotation of the drill string (not shown) and the imperfect seal formed by actively controlled sealing elements 600a and 600b, the injected lubrication fluid (not shown) that lubricates the lower actively controlled sealing element 600b may eventually work its way below lower actively controlled sealing element 600b and join the return flow of fluids (not shown) to the MPD choke manifold (not shown) disposed on the surface (not shown). The lubrication fluid (not shown) that lubricates upper actively controlled sealing element 600a may be collected in the trip tank (not shown).

Continuing, FIG. 3D shows a hybrid cross-sectional view of independent seal sleeves 800a and 800b for use as part of an annular sealing system (e.g., 400). In some applications, the annular sealing system (e.g., 400) may use independent seal sleeves 800a and 800b each of which include an actively controlled sealing element 600a or 600b that are disposed on their own respective mandrel 802a or 802b. Independent seal sleeve 800a includes first spacer portion 804a disposed on an upper distal end of actively controlled sealing element 600a and second spacer portion 806b disposed on the lower distal end of actively controlled sealing element 600a. Similarly, independent seal sleeve 800b includes first spacer portion 804b disposed on an upper distal end of actively controlled sealing element 600b and second spacer portion 806b disposed on a lower distal end of actively controlled sealing element 600b. Independent seal sleeves 800a and 800b are completely independent from one another. As such, in contrast to the use of a dual seal sleeve (e.g., 700), independent seal sleeves 800a and 800b may be independently engaged or disengaged and independently moved in between bit runs while the annular sealing system (e.g., 400) maintains the pressure tight seal on the annulus (not shown). This permits upper actively controlled sealing element 600a to be retrieved independently with a single run of a running tool or, once upper actively controlled sealing element 600a has been removed, lower actively controlled sealing element 600b may be retrieved independently with a single run of the running tool, all while maintaining annular pressure. However, both actively controlled sealing elements 600a and 600b could potentially be retrieved with a single run of a running tool (not shown).

In operation, upper actively controlled sealing element 600a and lower actively controlled sealing element 600b may be disposed within the annular sealing system (e.g., 400) such that upper actively controlled sealing element 600a may be positioned for engagement by the upper annular packer system (e.g., 500a) and lower actively controlled sealing element 600b may be positioned for engagement by the lower annular packer system (e.g., 500b). The drill string (not shown) may be disposed through an inner diameter of the annular sealing system (e.g., 400) and the marine riser (not shown) may be pressurized by engaging one or more of upper actively controlled sealing element 600a or lower actively controlled sealing element 600b by the upper annular packer system (e.g., 500a) or the lower annular packer system (e.g., 500b) respectively.

In certain applications, upper actively controlled sealing element 600a and lower actively controlled sealing element 600b are engaged at the same time to provide a redundant seal. For reasons beyond the scope of this disclosure, one of upper actively controlled sealing element 600a or lower actively controlled sealing element 600b may wear at a faster rate than the other (typically upper actively controlled sealing element 600a). If one of upper actively controlled sealing element 600a or lower actively controlled sealing element 600b wears out in between bit runs, the worn actively controlled sealing element 600a or 600b must be replaced, resulting in a premature end to drilling activities, requiring substantial non-productive downtime, and the time-consuming, complex, and costly task of depressurizing the marine riser (not shown). As such, it is highly desirable to extend the life of actively controlled sealing elements 600a and 600b and be able to replace one or more of worn actively controlled sealing element 600a or 600b without depressurizing the marine riser (not shown), thereby minimizing non-productive downtime and safely maintaining pressure.

FIG. 4A shows an elevation view of ACD annular sealing system 400. Annular sealing system 400 includes upper annular packer system 500a disposed above lower annular packer system 500b. Lubrication injection port 402 is disposed between upper annular packer system 500a and lower annular packer system 500b and is configured to inject lubrication fluid (not shown) into the lubrication chamber (not shown) formed there between. Continuing, FIG. 4B shows a hybrid cross-sectional elevation view of annular sealing system 400. Annular sealing system 400 includes a central lumen 402 that extends the longitudinal length of annular sealing system 400. While upper annular packer 500a (and upper actively controlled sealing element 600a) and lower annular packer 500b (and lower actively controlled sealing element 600b) are shown in the disengaged state in the figure, when they are engaged to create an annular seal surrounding the drill string (not shown), lubrication chamber 406 is formed between upper annular packer 500a and lower annular packer 500b.

FIG. 5A shows a hybrid cross-sectional elevation view of ACD annular sealing system 400 with a dual seal sleeve (e.g., 700) disposed within central lumen 404 and operatively positioned within upper annular packer system 500a and lower annular packer system 500b. Central lumen 404 may have a diameter suitable to receive the dual seal sleeve 700 or independent seal sleeves (e.g., 800a or 800b). The seal sleeves (e.g., 700 or 800a, 800b) may be disposed within annular sealing system 400 and secured in place with a plurality of upper locking dogs 406a and a plurality of lower locking dogs 406b that extend radially inward.

At the start of an operation requiring an annular seal on the wellbore (e.g., 102), the rig crew uses the surface based control system (e.g., 1000) to extend a plurality of lower locking cylinders 406b which extend radially into the central bore of the housing of annular sealing system 400. This plurality of lower locking cylinders 406b act as a landing shoulder to properly place dual seal sleeve 700 within the central bore of the housing of annular sealing system 400. Once the plurality of lower locking cylinders 406b are fully extended, the rig crew runs dual seal sleeve 700 from the surface into the housing of ACD 400. Once dual seal sleeve 700 has landed on the plurality of lower locking cylinders 406b, the rig crew uses the surface based control system (e.g., 1000) to close a plurality of upper locking cylinders 406a located just above the top of dual seal sleeve 700. The plurality of upper locking cylinders 406a acts to contain dual seal sleeve 700 in place once pressure is applied to it. With dual seal sleeve 700 landed in place and the plurality of upper locking cylinders and the plurality of lower locking cylinders engaged, upper intermediate upper locking cylinders 408a and intermediate lower locking cylinders 408b may be engaged to mechanically isolate upper actively controlled sealing element 600a and lower actively controlled sealing element 600b. Once dual seal sleeve 700 is locked in place, the rig crew uses the surface based control system (e.g., 1000) to actuate upper annular packer system 500a and lower annular packer system 500b to engage upper actively controlled sealing element 600a and lower actively controlled sealing element 600b. Once locked in place, dual seal sleeve 700 does not move axially up or down.

In the case (not shown) of independent seal sleeves (e.g., 800a, 800b), a substantially similar process is followed, where lower independent seal sleeve 800b the same process is followed where the lower independent seal sleeve (e.g., 800b) is landed on the plurality of extended lower locking cylinders 406b, the plurality of lower intermediate locking cylinders 408b, disposed above the top of landed lower independent seal sleeve (e.g., 800b), are extended to secure lower independent seal sleeve (e.g., 800b) in place. Similarly, a plurality of upper intermediate locking cylinders 408a may be extended to create a landing profile for upper independent seal sleeve (e.g., 800a) and once landed, the plurality of upper locking cylinders 406a may be extended to secure upper independent seal sleeve (e.g., 800a) in place.

Continuing, FIG. 5B shows a detailed hybrid cross-sectional elevation view of upper actively controlled sealing element 600a disposed within upper annular packer system 500a of annular sealing system 400. In dual seal sleeve 700a embodiments, the size, shape, and configuration of mandrel 702 and vented intermediate spacer 706 may vary to ensure that upper Actively controlled sealing element 600a is properly positioned within upper annular packer system 500a. In independent seal sleeves (e.g., 800a, 800b) embodiments, the size, shape, and configuration of the mandrels (e.g., 802a, 802b) for the upper independent seal sleeve (e.g., 800a) may vary to ensure that upper actively controlled sealing element 600a is properly positioned within upper annular packer system 500a.

Continuing, FIG. 5C shows a detailed hybrid cross-sectional elevation view of lower Actively controlled sealing element 600b disposed within lower annular packer system 500b of annular sealing system 400. In dual seal sleeve 700a embodiments, the size, shape, and configuration of mandrel 702 and vented intermediate spacer 706 may vary to ensure that lower actively controlled sealing element 600b is properly positioned within lower annular packer system 500b. In independent seal sleeves (e.g., 800a, 800b) embodiments, the size, shape, and configuration of the mandrels (e.g., 802a, 802b) for the lower independent seal sleeve (e.g., 800b) may vary to ensure that lower actively controlled sealing element 600b is properly positioned within lower annular packer system 500b.

FIG. 6A shows a cross-sectional detailed view of actively controlled sealing element 600a or 600b disposed within an annular packer system 500a or 500b of an annular sealing system (e.g., 400), where annular packer 502a or 502b is in a disengaged state. Upper annular packer system 500a includes a piston-actuated 504a annular packer 502a disposed within arcuate housing 506a. Annular packer 502a is composed of an elastomer or rubber body with a plurality of fingers, or protrusions, 508a that are configured to travel within arcuate housing 506a when piston 504a is actuated. Actively controlled sealing element 600a includes a central lumen 602a through which drill string 106, or portions thereof, may pass therethrough. Similarly, lower annular packer system 500b includes a piston-actuated 504b annular packer 502b disposed within arcuate housing 506b. Annular packer 502b is composed of an elastomer or rubber body with a plurality of fingers, or protrusions, 508b that are configured to travel within arcuate housing 506b when piston 504b is actuated. Actively controlled sealing element 600b includes a central lumen 602b through which drill string 106, or portions thereof, may pass therethrough.

Continuing, FIG. 6B shows a cross-sectional detailed view of actively controlled sealing element 600a or 600b disposed within an annular packer system 500a or 500b of an ACD-type annular sealing system (e.g., 400), where annular packer 502a or 502b is in an engaged state. Actively controlled sealing elements 600a or 600b are not normally in sealing engagement with drill string 106 disposed within and are only forced into sealing engagement when actuated by an actuation mechanism and that actuation must be continuously applied to maintain the sealing engagement. Actively controlled sealing elements 600a or 600b must be engaged by spherical annular packers 502a or 502b that, when actuated, travel within arcuate hosing 506a or 506b such that annular packer 502a or 502b come into contact with and squeeze a middle portion of actively controlled sealing element 600a or 600b, such that they form an interference fit with drill string 106 disposed therethrough. Annular packers 502a, 502b resist deformation such that the application of a lower hydraulic closing pressure causes the ID of the central bore of annular packers 502a, 502b to constrict to a lesser degree while a higher hydraulic closing pressure causes the ID of the central bore of annular packer 502a, 502b to constrict to a greater degree. From a fully relaxed state, increasing the hydraulic closing pressure acting on piston 504a, 504b causes annular packer 502a, 502b to deform and annular packer 502a, 502b material in the central bore makes contact with the OD of the seal sleeve (e.g., 700, 800a, 800b). Continued application of closing pressure increasingly deforms annular packer 502a, 502b causing the seal sleeve (e.g., 700, 800a, 800b) to deform into an hourglass shape. The externally applied force causes the seal insert (e.g., 620) to deflect radially inward until it contacts the drill string, creating the annular seal. As such, actively controlled means that sealing elements 600a or 600b are only engaged while actuation is applied, and once actuation is removed, sealing elements 600a or 600b disengage. 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 sealing element 600a or 600b.

For example, when hydraulically actuated, piston 504a travels causing the elastomer or rubber portion of annular packer 502a to travel within arcuate housing 506a such that annular packer 502a and fingers 508a come into contact with upper actively controlled sealing element 600a. When annular packer 502a is sufficiently actuated, upper actively controlled sealing element 600a squeezes on drill string 106, such that wear-resistant seal insert 620a and buffer material 630a come into contact with a circumference of a portion of drill string 106, resulting in a pressure tight interference fit surrounding drill string 106. Whether engaged or not, upper actively controlled sealing element 600a remains stationary while drill string 106 rotates. Similarly, when hydraulically actuated, piston 504b travels causing the elastomer or rubber portion of annular packer 502b to travel within arcuate housing 506b such that annular packer 502b and fingers 508b come into contact with lower actively controlled sealing element 600b. When annular packer 502b is sufficiently actuated, lower actively controlled sealing element 600b squeezes drill string 106, such that wear-resistant seal insert 620b and buffer material 630b come into contact with a circumference of a portion of drill string 106, resulting in a pressure tight interference fit surrounding drill string 106. Whether engaged or not, lower actively controlled sealing element 600b remains stationary while drill string 106 rotates.

In dual seal sleeve embodiments, after landing the dual seal sleeve (e.g., 700) within the annular sealing system (e.g., 400), an annular seal (not shown) may be created by engaging upper annular packer 500a and/or lower annular packer 500b to engage upper actively controlled sealing element 600a and/or lower actively controlled sealing element 600b respectively. The extent to which pistons 504a, 504b are actuated is controlled by the injection of hydraulic power fluid into the actuation chamber (not shown) of pistons 504a, 504b. As such, the amount of closing pressure exerted on actively controlled sealing elements 600a, 600b may be controlled by the injection of hydraulic power fluid into the actuation chamber (not shown) of pistons 504a, 504b. Thus, the drilling rig (not shown) may provide sufficient closing pressure to ensure that actively controlled sealing elements 600a, 600b 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 sealing elements 600a, 600b wear.

FIG. 7A shows a hybrid cross-sectional view of an actively controlled sealing element 600a, 600b of an annular sealing system (e.g., 400) in an unworn state. Seal insert 620a, 620b and buffer material 630a, 630b are in a substantially new condition such that, when engaged, seal insert 620a, 620b and buffer material 630a, 630b make contact, and form an interference fit with, the drill string (not shown).

Continuing, FIG. 7B shows a hybrid cross-sectional view of an actively controlled sealing element 600a, 600b of the ACD annular sealing system (e.g., 400) in a partially worn state. Over time, due to sustained use, seal insert 620a, 620b and buffer material 630a, 630b are partially worn such that insert 620a, 620b and buffer 630a, 630b materials are partially worn away in the ID of actively controlled sealing element 600a, 600b. Upon removal of actuation pressure, the shape of the central lumen 602a, 602b is deformed, often bulbous. Consequently, because of the partially worn state of actively controlled sealing element 600a, 600b, the annular packer system (e.g., 500a, 500b) may require more closing pressure to cause the worn sealing element 600a, 600b to make sufficient closing contact with the drill string (not shown) to maintain the pressure tight annular seal.

Continuing, FIG. 7C shows a hybrid cross-sectional view of an actively controlled sealing element 600a, 600b of the annular sealing system (e.g., 400) in a further worn state. Wear of actively controlled sealing element 600a, 600b occurs from the inside of the element at the interface between the OD of the drill string (not shown) and the ID of actively controlled sealing element 600a, 600b through two primary modes: abrasion and erosion. Abrasion of the seal element is caused by scraping action of the drill string (not shown) as it rotates and reciprocates in contact with actively controlled sealing element 600a, 600b. Excess wear due to abrasion may occur when rough edges such as hard banding or die marks on the tool joints (not shown) pass through actively controlled sealing element 600a, 600b. Abrasion is common where the pressure differential between the fluids above and below each actively controlled sealing element 600a, 600b is low and the fluid flow across each actively controlled sealing element 600a, 600b is negligible. Erosion of the annular seal is caused by the high speed collision of fluid particles with actively controlled sealing element 600a, 600b. Wear due to erosion may occur where the pressure differential between the fluids above and below each actively controlled sealing element 600a, 600b is high and the fluid flow across the element is not negligible. Both erosion and abrasion remove material from actively controlled sealing element 600a, 600b from the interface between the drill pipe (not shown) and actively controlled sealing element 600a, 600b.

Continued use of the partially worn actively controlled sealing element 600a, 600b causes further wear to seal insert 620a, 620b and buffer material 630a, 630b such that the shape of the central lumen 602a, 602b is even more deformed, usually bulbous. Consequently, because of the substantially worn state of sealing element 620a, 620b, the annular packer system (e.g., 500a, 500b) may require even more hydraulic actuation to provide sufficient closing pressure that causes the substantially worn actively controlled sealing element 600a, 600b to make sufficient closing contact with the drill string (not shown) to maintain the pressure tight annular seal.

Continuing, FIG. 7D shows a hybrid cross-sectional view of an actively controlled sealing element 600a, 600b of the ACD annular sealing system (e.g., 400) in a worn state. Eventually, seal insert 620a, 620b is breached approximately at its midpoint, leaving a band of exposed elastomer buffer material 630a, 630b in contact with the drill string (not shown). Due to the bending of seal insert 620a, 620b by external pressure, seal insert 620a, 620b continues to support the elastomer buffer material 630a, 630b even after the initial breach. With continued use, the support of the remaining seal insert 620a, 620b is eventually lost. When this occurs, the annular packer (e.g., 502a, 502b) pushes on the unsupported buffer material 630a, 630b. Without the support of seal insert 620a, 620b, the annular packer system (e.g., 500a, 500b) must close to greater degree to maintain seal integrity on buffer material 630a, 630b. Continued use of the substantially worn actively controlled sealing element 600a, 600b causes further wear to seal insert 620a, 620b and buffer material 630a, 630b such that a substantial portion of seal insert 620a, 620b is fully worn away and the central lumen 602a, 602b is even more bulbous and consists primarily of buffer material 630a, 630b. Consequently, because of the fully worn state of actively controlled sealing element 600a, 600b, the annular packer system (e.g., 500a, 500b) may require even more hydraulic actuation, if even possible at all, to cause the fully worn sealing element 602a, 602b to make sufficient closing contact with the drill string (not shown) to maintain the annular seal, if even possible at all. In such circumstances, buffer material 630a, 630b must be relied upon to make the closing contact with the drill string (not shown) in an attempt to maintain the annular seal. However, buffer material 630a, 630b is typically composed of polyurethane and is not wear resistant. While buffer material 630a, 630b wears rather quickly with rotation, it likely has a functional life on the order of magnitude of hours that allows the operator to plan replacement of the failed or failing Actively controlled sealing element 600a, 600b at an opportune time.

While the description above was made with reference to an annular sealing system, one of ordinary skill in the art, having the benefit of this disclosure will appreciate it applies with equal force to applications having a single actively controlled sealing element, such as, for example, an annular closing system.

One of the many challenges presented in deepwater operations is maintaining a pressure tight annular seal in a manner that enhances the safety of rig personnel and optimizes productive uptime of the drilling rig, which has the effect of reducing operating costs. In reality, all sealing elements fail over time for various reasons well known in the industry, some of which have been discussed herein. In conventional applications that use passive sealing elements, there is typically very limited to no information as to wear state of sealing elements unless and until the seal fails. If a seal unexpectedly fails, the marine riser may be depressurized and may result in dangerous situation with respect to the drilling rig and the rig personnel. If the marine riser must be depressurized, the sealing element must be retrieved and replaced, and the marine riser must be pressurized once again. This results in non-productive downtime and increases operational costs.

Accordingly, in one or more embodiments of the present invention, methods of operating an actively controlled sealing element are disclosed that advantageously extend the runtime of one or more actively controlled sealing elements and reduce the amount of wear induced by a transiting tool joint. In certain embodiments, the activation of two or more independent actively controlled sealing elements are coordinated as a function of the position of tool joints in relation to the actively controlled sealing elements. In other embodiments, the activation of two or more independent actively controlled sealing elements are sequenced using a first actively controlled sealing element until the end of its design life and then utilizing a second actively controlled sealing element. In still other embodiments, a single actively controlled sealing element may be variably actuated as a function of the position of tool joints in relation to the actively controlled sealing element. Advantageously, runtime of actively controlled sealing elements may be extended, improving productivity and reducing operating costs.

Over the course of the life of an actively controlled sealing element (e.g., 600a, 600b), the wall thickness at the middle point of its seal insert (e.g., 620a, 620b) is gradually reduced. Gradual removal of the material from the ID is offset by injecting incrementally more hydraulic fluid into the piston (e.g., 504a, 504b) of the annular packer system (e.g., 500a, 500b) in which it is disposed. Increased actuation causes the piston (e.g., 504a, 504b) to further close on the annular packer (e.g., 502a, 502b), backfilling the material worn from the sealing interface.

For the annular packer system (e.g., 500a, 500b) to close to greater degree, the internal resistance of the annular packer (e.g., 502a, 502b) must also be overcome. The internal resistance of the annular packer (e.g., 502a, 502b) is an important dynamic when considering the hydraulic closing pressure required to seal on various diameters. If the annular packer (e.g., 502a, 502b) must seal against a large OD tubular or a new actively controlled sealing element (e.g., 600a, 600b), less hydraulic closing pressure is required to overcome the internal resistance of the annular packer (e.g., 502a, 502b) itself. If the annular packer (e.g., 502a, 502b) must seal against a small OD tubular or a worn actively controlled sealing element (e.g., 600a, 600b), more hydraulic closing pressure is required to overcome the internal resistance of the annular packer (e.g., 502a, 502b). This dynamic is applied practically in that once the support of the seal insert (e.g., 620a, 620b) is lost, a significantly higher amount of hydraulic closing pressure must be applied to the annular packer system (e.g., 500a, 500b) to maintain seal integrity of the affected element. This change in the hydraulic closing pressure is sudden and drastic representing an inflection point which occurs when transitioning from an insert (e.g., 620a, 620b) supported sealing engagement to sealing engagement without the insert (e.g., 620a, 620b), signifying that the actively controlled sealing element (e.g., 600a, 600b) has reached the end of its design life.

In one or more embodiments of the present invention, a method of operating a plurality of actively controlled sealing elements (e.g., 600a, 600b) may be based on the proximity of a tool joint (not shown) or external upset (non-typical feature having a different geometry or larger OD than the body section of the tubular drill string) in relation to each actively controlled sealing element (e.g., 600a, 600b). Advantageously, this extends the runtime of the actively controlled sealing elements (e.g., 600a, 600b) by preventing the passage of a tool joint (not shown) or other feature through closed non-rotating actively controlled sealing elements (e.g., 600a, 600b) to prevent excessive wear of actively controlled sealing elements (e.g., 600a, 600b). This process of coordinating the activation of actively controlled sealing elements (e.g., 600a, 600b) may be performed manually by a human operator or automatically using a control system (e.g., 1000). In order to coordinate the activation of actively controlled sealing elements (e.g., 600a, 600b) based on the approximate location of tool joints (not shown) or other features (not shown) in relation to non-rotating actively controlled sealing elements (e.g., 600a, 600b), we may determine the approximate location of the tool joints (not shown) or external upset (not shown) anticipated to transit the actively controlled sealing elements (e.g., 600a, 600b) and 2) determine the approximate location of the actively controlled sealing elements (e.g., 600a, 600b). With this information, we may coordinate the activation of actively controlled sealing elements (e.g., 600a, 600b) with the transiting of tool joints (not shown). Advantageously, the operational life of actively controlled sealing elements (e.g., 600a, 600b) may be extended.

In one or more embodiments of the present invention, a first method of approximating the location of tool joints (not shown) in relation to the non-rotating actively controlled sealing elements (e.g., 600a, 600b) may use one or more sensors (not shown) that directly measure qualities of the drill string (e.g., 106) in the vicinity of the sensors (not shown). One or more sensors (not shown) measuring qualities of the drill string (e.g., 106) may be disposed parallel to the main bore axis at or near the landed location of each actively controlled sealing element (e.g., 600a, 600b). The sensors (not shown) transmit sensor data to the control system (e.g., 1000), which processes the data to determine the absence or presence of a tool joint (not shown) at each sensor (not shown) location. One of ordinary skill in the art will appreciate that the one or more sensors (not shown) may utilize a variety of specific measurement techniques measuring the gauge of the drill string (e.g., 106), such as with a caliper, or changes in the magnetic field, such as with a gauss meter or Hall effect meter. The type or kind of sensor (not shown) is not important, so long as the sensor (not shown) is able to detect the presence of an adjacent tool joint (not shown). Multiple sensors (not shown) may be deployed within an annular sealing system (e.g., 400) and preferentially above and below each of the actively controlled sealing elements (e.g., 600a, 600b) to detect the approximate position of a tool joint (not shown) within the annular sealing system (e.g., 400).

In one or more embodiments of the present invention, a second method of approximating the location of tool joints (not shown) in relation to the non-rotating actively controlled sealing elements (e.g., 600a, 600b) is to track approximate positions of tool joints (not shown) indirectly from existing instrumentation available on a modern drilling rig (not shown).

First, we determine the depth of each tool joint (not shown) relative to the rig floor (not shown) and the depth of each of actively controlled sealing elements (e.g., 600a, 600b) relative to the rig floor (not shown). In most cases, the driller keeps account of the type, order, and length of each component of the drill string (e.g., 106) in a tally book. Included in the driller's responsibilities is bookkeeping that enables the driller to calculate the bit measure depth to verify the calculated depth of the Electronic Drilling Recorder (“EDR”) system. The driller accomplishes this using the known length and position of each component of the drill string (e.g., 106) to calculate the total length of the drill string (e.g., 106). With the known total drill string (e.g., 106) length, the driller may subtract the length of drill string (e.g., 106) above the rotary table (not shown) to calculate the measure depth of the drill bit (e.g., 108). A quick way to determine the length of drill string (e.g., 106) above the rotary table (not shown) is to use the block height (not shown). If the rig (not shown) is part of a floating drilling unit (not shown) the travelling block (not shown) may compensate for heave action caused by wave motion. In this case, the block (not shown) height may be corrected further by including a correction factor from a heave compensation system (not shown).

Calculation of block height is well known in the art. While drilling rig (not shown) configurations vary, each rig crew may use a nominal representation of block height. For example, block height may be represented by the elevation of the travelling block (not shown) itself, the elevation of the hook (not shown) or attachment point (not shown) holding a top drive (not shown), or the elevation of the elevators (not shown) above the rig floor (not shown). In practice, block height may represent the elevation of any component (not shown) attached to the travelling block assembly (not shown) and appropriate offset elevation values applied as needed. For the purpose of this disclosure, block height is defined as the externally visible interface between a top drive (not shown) saver sub pin end connection (not shown) connected to the uppermost box end connection (no shown) of the drill string (e.g., 106).

The above calculations of measure depth of various drillstring components may be performed by a human driller or by the EDR system (not shown). Using the above information, the driller or the control system (e.g., 1000) can provide an accurate indication of the position of any component of drill string (e.g., 106) or connections between drill string (e.g., 106) components relative to the rig floor (not shown).

Second, we determine the depth of each actively controlled sealing elements (e.g., 600a, 600b) relative to the rig floor (not shown). Similar to the drill string (e.g., 106), the height of each component (not shown) in the riser string (not shown) or wellhead stack up (not shown) is a known value. In applications drilling from fixed platforms (not shown), a driller may use the known elevation of the rig floor (not shown) above the ground level or mean sea level (“MSL”) and the known elevation of an actively controlled sealing element (e.g., 600a, 600b) above the ground level or MSL to determine the depth of each actively controlled sealing elements (e.g., 600a, 600b) relative to the rig floor (not shown). In deepwater applications drilling from a floating vessel (not shown), the known elevation of an actively controlled sealing element (e.g., 600a, 600b) in reference to the rig floor (not shown) may be corrected to account for heave action caused by wave motion. In this case, the elevation of an actively controlled sealing element (e.g., 600a, 600b) in reference to the rig floor (not shown) may be corrected further by including a correction factor from a riser tensioning system (not shown).

Using the locations of tool joints (not shown) and the locations of actively controlled sealing elements (e.g., 600a, 600b) relative to the rig floor (not shown), the driller or control system (e.g., 1000) may determine the location of tool joints (not shown) relative to the locations of actively controlled sealing elements (e.g., 600a, 600b).

In one or more embodiments of the present invention, a third method of approximating the location of tool joints (not shown) in relation to the non-rotating actively controlled sealing elements (e.g., 600a, 600b) may use one or more proxy variables which indicate a tool joint (not shown) is likely to be disposed within a actively controlled sealing element (e.g., 600a, 600b). Proxy variables do not directly measure an object of interest, but instead help characterize what objects of interest are doing. For example, there is no direct measurement of bit depth on a drilling rig (not shown). Instead, variables such as block position and hookload are used in tandem to track whether the drill string (e.g., 106) is supported by the travelling block (not shown) or the slips (not shown). The control system (e.g., 1000) includes depth tracking software that uses this information to assert when block (not shown) motion equates to drill string (e.g., 106) motion allowing block position and hookload to be used to derive bit depth. Such combinations are commonly used in the drilling industry and are well known to one of ordinary skill in the art.

Similarly, the use of proxy variables allows the operator to define values of block position at which a tool joint (not shown) is likely to be disposed within an actively controlled sealing element (e.g., 600a, 600b). This may be done quickly by assuming each joint (not shown) of drill pipe (not shown) is of the same dimensions or within a consistent range of dimensions. Typically using all Range II pipe or all Range III pipe, as is known in the drilling industry, is sufficiently precise for this method and variation between individual joints may be ignored. This simplifying assumption allows the rig crew or control system (e.g., 1000) to find the block heights corresponding to tool joints (not shown) in the seal sleeves (e.g., 700, 800a, 800b) using a three (3) step graphical plotting process.

First, FIG. 8A shows a plot of actuation parameters of the actively controlled sealing elements (e.g., 600a, 600b) and block height versus time in accordance with one or more embodiments of the present invention. A plot of actively controlled sealing element (e.g., 600a, 600b) actuation parameters versus time and block height versus time may be created using data showing the progression of the drill string (e.g., 106) being lowered or raised by one stand length. For current generation annular sealing systems (e.g., 400), closing pressures of the upper and the lower annular packer systems (e.g., 500a, 500b) and block height suffice.

Second, FIG. 8B shows a plot of actuation parameters of the actively controlled sealing elements (e.g., 600a, 600b) and block height versus time with vertical reference lines that traverse the full scale of the y-axis indicate where in the time sequence (x-axis) a tool joint (not shown) enters a seal sleeve (e.g., 700, 800a, 800b) in accordance with one or more embodiments of the present invention. A tool joint (not shown) entering the seal sleeve (e.g., 700, 800a, 800b) may indicated by fluctuations in the closing pressure as the block (not shown) moves or also by changes in other variables associated with the transit of a tool joint (not shown) or another feature.

Third, FIG. 8C shows a plot of actuation parameters of the actively controlled sealing elements (e.g., 600a, 600b) and block height versus time where horizontal reference lines that traverse the full scale of the x-axis indicate where on the block height (y-axis) the vertical lines intersect with the block height, in accordance with one or more embodiments of the present invention. The y-axis values of block height where the horizontal lines intersect the axis are read and stored as block heights corresponding to tool joints (not shown) in a seal sleeve (e.g., 700, 800a, 800b). This process provides an approximation of the tool joint (not shown) positions relative to the actively controlled sealing elements (e.g., 600a, 600b) and needs only be performed occasionally to verify the calibration. Where the actively controlled sealing elements (e.g., 600a, 600b) are within 2 or 3 stands of drill pipe (not shown) from the rig floor (not shown), additive effect of error due variation in the length of drill pipe stands is minimal. Where the actively controlled sealing element (e.g., 600a, 600b) are further away from the rig floor (not shown), direct calculation of the tool joint (not shown) positions with respect to the actively controlled sealing elements (e.g., 600a, 600b) positions may be preferable to avert error due variation in the length of drill pipe stands. This process allows block height to serve as a proxy for tool joint (not shown) position when the drill string (e.g., 106) is not set in slips (not shown).

In one or more embodiments of the present invention, a fourth method of approximating the location of tool joints (not shown) in relation to the non-rotating actively controlled sealing elements (e.g., 600a, 600b) is to combine the use of sensors (not shown) and position tracking capabilities to improve the knowledge gathered by the sensor (not shown) and the accuracy of the position tracking solution. In this method, one or more sensors (not shown) may be used to detect the presence of a tool joint (not shown) or other drill string feature (not shown) with the annular sealing system 400. The control system (e.g., 1000) interprets data from one or more sensors (not shown) to indicate when a tool joint (not shown) is detected. The control system (e.g., 1000) may process the signal to mean that a tool joint (not shown) is at the depth of the sensor (not shown) and use the depth tracking system to adjust the depth of the tool joint (not shown) as the travelling block (not shown) moves down or up.

Once the location of tool joints (not shown) in relation to the non-rotating actively controlled sealing elements (e.g., 600a, 600b) is determined, the activation of the actively controlled sealing elements (e.g., 600a, 600b) may be coordinated based on a desired state of the actively controlled sealing elements (e.g., 600a, 600b).

For the purposes of illustration, coordination of the activation of actively controlled sealing elements (e.g., 600a, 600b) this process may be demonstrated on an annular sealing system (e.g., 400) that includes an upper annular packer system (e.g., 500a) configured to receive an upper actively controlled sealing element (e.g., 600a) and a lower annular packer system (e.g., 500b) configured to receive a lower actively controlled sealing element (e.g., 600b). The actively controlled sealing elements (e.g., 600a, 600b) may be disposed as part of a dual seal sleeve (e.g., 700) or deployed as two independent seal sleeves (e.g., 800a, 800b). Notwithstanding, one of ordinary skill in the art, having the benefit of this disclosure will recognize that the coordination of activation may be scaled to any number of actively controlled sealing elements in accordance with one or more embodiments of the present invention.

Once the non-rotating actively controlled sealing elements (e.g., 600a, 600b) are installed, a chamber is formed between them. This chamber may be open when both the upper and the lower actively controlled sealing elements (e.g., 600a, 600b) are deactivated, open on one end when the upper actively controlled sealing element (e.g., 600a) is deactivated or the lower actively controlled sealing element (e.g., 600b) is deactivated, or closed on both ends when both the upper and the lower Actively controlled sealing elements (e.g., 600a, 600b) are activated.

To coordinate the activation of independently controlled actively controlled sealing elements (e.g., 600a, 600b) based on the relative proximity of a tool joint (not shown) or other feature, the operator must initially determine the location of the tool joint (not shown) relative to the actively controlled sealing elements (e.g., 600a, 600b) as discussed above.

FIG. 9A shows tool joint 107 about to transit an upper actively controlled sealing element 600a of, for example, an annular sealing system 400 in accordance with one or more embodiments of the present invention. Assuming the initial condition is that both upper actively controlled sealing element 600a and lower actively controlled sealing element 600b are actuated and engaged such that they are squeezing on the body section of the drill pipe (of the tubular drill string), tool joint (or external upset) 107 may be determined to be approaching upper annular packer system 500a. The control system (e.g., 1000) may determine (via sensor, position tracking, or some combination thereof as disclosed herein) that tool joint 107 is nearing upper actively controlled sealing element 600a of upper annular packer system 500a. For example, as tool joint 107 approaches upper actively controlled sealing element 600a, the control system (e.g., 1000) receives a signal from a sensor (not shown), derives the position of tool joint 107 from tool joint position tracking, or some combination thereof. When the control system (e.g., 1000) has determined the tool joint 107 is approaching the upper actively controlled sealing element 600a, while the lower actively controlled sealing element 600b is activated and engaged forming an interference fit with drill string 106. Closure of lower actively controlled sealing element 600b seals the wellbore below the upper actively controlled sealing element 600a. Once lower actively controlled sealing element 600b is closed, upper actively controlled sealing element 600a may be opened prior to entry of tool joint 107 into upper actively controlled sealing element 600a.

Continuing, FIG. 9B shows tool joint 107 transiting upper actively controlled sealing element 600a of ACD annular sealing system 400 in accordance with one or more embodiments of the present invention. With upper actively controlled sealing element 500a opened or relaxed, tool joint 107 enters upper actively controlled sealing element 600a with significantly less force or no force at all being applied to drill string 106 by upper actively controlled sealing element 600a, reducing the effects of heat, abrasion, and erosion on the non-rotating upper actively controlled sealing element 600a.

Continuing, FIG. 9C shows tool joint 107 transiting out of upper actively controlled sealing element 600a of annular sealing system 400 in accordance with one or more embodiments of the present invention. As drilling progresses, tool joint 107 continues to move downward toward lower actively controlled sealing element 600b and into chamber formed between the two non-rotating actively controlled sealing elements 600a, 600b.

Continuing, FIG. 9D shows tool joint 107 transiting in between upper actively controlled sealing element 600a and lower actively controlled sealing element 600b of annular sealing system 400 in accordance with one or more embodiments of the present invention. Once tool joint 107 clears upper actively controlled sealing element 500a, drill string 106 may be disposed within upper actively controlled sealing element 600a and lower actively controlled sealing element 600b and tool joint 107 may be in the central lumen formed in between upper actively controlled sealing element 600a and lower actively controlled sealing element 600b. Upper annular packer system 500a and lower annular packer system 500b may be actuated to engage with upper actively controlled sealing element 600a and lower actively controlled sealing element 600b on drill string 106. As tool joint 107 continues to move downward, the control system (e.g., 1000) may receive a signal from a sensor (not shown) or otherwise determine the position of tool joint 107 relative to lower actively controlled sealing element 600b. When the control system (e.g., 1000) determines that tool joint 107 is approaching lower actively controlled sealing element 600b, upper annular packer 500a may be actuated to engage upper actively controlled sealing element 600a on drill string 106.

Continuing, FIG. 9E shows tool joint 107 starting to transit lower actively controlled sealing element 600b of annular sealing system 400 in accordance with one or more embodiments of the present invention. Closure of upper actively controlled sealing element 600a maintains an annular seal. Once established, lower actively controlled sealing element 600b may be opened prior to entry of tool joint 107 into lower actively controlled sealing element 600b.

Continuing, FIG. 9F shows tool joint 107 transiting lower actively controlled sealing element 600b of annular sealing system 400 in accordance with one or more embodiments of the present invention. With lower actively controlled sealing element 600b in the opened or relaxed state, tool joint 107 may fully enter and transit lower actively controlled sealing element 600b with significantly less force or no force at all being applied to drill string 106 or tool joint 107 by lower actively controlled sealing element 600b, reducing the effects of heat, abrasion, and erosion on the non-rotating lower actively controlled sealing element 600b.

Continuing, FIG. 9G shows tool joint 107 transiting out of the lower actively controlled sealing element 600b of annular sealing system 400 in accordance with one or more embodiments of the present invention.

Continuing, FIG. 9H shows tool joint 107 disposed below lower actively controlled sealing element 600b of ACD annular sealing system 400 in accordance with one or more embodiments of the present invention. Once tool joint 107 clears lower actively controlled sealing element 600b, the body of the drill string 106 may be disposed within lower actively controlled sealing element 600b. At this point, with tool joint 107 having transited both upper Actively controlled sealing element 600a and lower actively controlled sealing element 600b, either upper actively controlled sealing element 600a or lower actively controlled sealing element 600b may be closed on drill string 106 with tool joint 107 safely out of the way. It may however be preferable to have only one actively controlled sealing element 600a or 600b closed to prolong seal element assembly life. One of ordinary skill in the art, having the benefit of this disclosure, will appreciate that this process may be repeated for each subsequent tool joint (not shown) in drill string 107. Notably, this process may be performed as drill string 106 is being moved downward or upward as well as during any type of operation in which drill string 106 is in the wellbore including when drilling, stripping, or reaming the well. By executing a seal against drill pipe rather and staging tool joints, leakage of the high pressure fluid contained by the non-rotating actively controlled sealing elements 600a, 600b occurs primarily as a result of pressure bleeding from the chamber when opening upper actively controlled sealing element 600a.

In one or more embodiments of the present invention, a method of sequentially activating (consuming) multiple actively controlled sealing elements (e.g., 600a, 600b) extends productive time by activating one actively controlled sealing element (e.g., 600a or 600b) for its full design life prior to activating another other actively controlled sealing element (e.g., 600b or 600a). In this way, an annular seal may be maintained for an extended prior of time, increasing productive time, and reducing operating costs.

A first actively controlled sealing element (e.g., 600a or 600b) may be engaged to close on the drill string (e.g., 106) without regard for the part of the tubular being disposed within the sealing element (e.g., 600a or 600b). As noted above, annular sealing systems (e.g., 400) may use a dual seal sleeve (e.g., 700) that includes two actively controlled sealing elements (e.g., 600a, 600b) disposed on a single mandrel (e.g., 702), or multiple independent seal sleeves, each of which includes an actively controlled sealing element (e.g., 600a or 600b). Unlike previously disclosed methods, there is no need for sensors (not shown) or depth tracking to inform the control system (e.g., 1000). Further, the distance between actively controlled sealing elements (e.g., 600a, 600b) may be of any length allowed by dimensions of the wellbore (e.g., 102) and marine riser system (e.g., 200).

For purposes of illustration, this process is described herein with respect to a dual seal sleeve (e.g., 700). One of ordinary skill in the art, having the benefit of this disclosure, will appreciate that this process may be extended to applications with any number of sealing elements (e.g., 600).

To operate two or more actively controlled sealing elements (e.g., 600a, 600b), an operator may determine which of the actively controlled sealing elements (e.g., 600a, 600b) to use first. For example, the operator may choose to use upper actively controlled sealing element 600a first. Once the operation requires the well to be isolated from the atmosphere, upper actively controlled sealing element (e.g., 600a) may be actuated and closed. Upper actively controlled sealing element (e.g., 600a) is actuated to force the element (e.g., 600a) into sealing engagement with drill string 106. When the drill pipe body is disposed within the closed upper actively controlled sealing element (e.g., 600a) the actuating mechanism forces the seal element (e.g., 600a) into sealing engagement with the smaller diameter drill pipe body. The upper actively controlled sealing element (e.g., 600a) remains closed as the drill string (e.g., 106) is lowered into or pulled from the wellbore, causing the tool joints (e.g., 107) to be forced into the closed upper actively controlled sealing element (e.g., 600a). The entry of the larger diameter tool joint (e.g., 107) pushes back against the element (e.g., 600a) and its actuation system, partially opening the element (e.g., 600a) while remaining in sealing engagement. Sealing element (e.g., 600a) wear caused by heat, abrasion, or erosion is allowed to occur during the interactions of the tool joint (e.g., 107) and seal element (e.g., 600a) with no preventative measures taken. As the drill string (e.g., 106) continues to move downward or upward, the tool joint (e.g., 107) exits the seal element (e.g., 600a). As the larger diameter tool joint (e.g., 107) exits, the seal element (e.g., 600a) is moved back to a more closed position to resume sealing engagement with the drill pipe body. It is expected that a portion of high pressure fluid contained by the seal element (e.g., 600a) leaks past the seal element (e.g., 600a) during the transition from sealing against the tool joint (e.g., 107) to sealing against the drill pipe body.

During the course of drilling operations, the passage of tool joints (e.g., 107) through the closed seal element (e.g., 600a) may inflict wear on the element (e.g., 600a). The operator may run the seal element (e.g., 600a) for a predetermined amount of time or for a specific set of operations. The operator may also use a condition monitoring system to determine when the first seal element (e.g., 600a) reaches the end of its design life. Upon reaching the end of the seal (e.g., 600a) design life or other metric specified by the user, the control system (e.g., 1000) may be functioned to close the second actively controlled sealing element (e.g., 600b) while the first element (e.g., 600a) remains in sealing engagement with the drill string (e.g., 106). Once the second element (e.g., 600b) is closed, the first element (e.g., 600a) may be disengaged or relaxed. The sequential activation method allows the system (e.g., 400) to fully consume a first element (e.g., 600a) prior to inflicting any significant wear on the second element (e.g., 600b), extending the runtime to be the sum of the runtime of each actively controlled sealing element (e.g., 600a, 600b).

Furthermore, the operator may also dispose different types of seal elements in the two more actuation mechanisms (e.g., 500a, 500b). For example, the operator may install one type of actively controlled sealing element in one of the annular packer systems (e.g., 500a, 500b) for stripping operations which comprise primarily axial movement of the drill string (e.g., 106) with little to no rotation and install another type of Actively controlled sealing element in another actuating mechanism (e.g., 500a, 500b) for drilling or reaming operations which comprise axial and rotational movement of the drill string (e.g., 106). Using the sequential activation method, the annular sealing system (e.g., 400) may be operated to utilize specific seal types for specific operations, extending the usable life of each actively controlled sealing element through use limited for a specific purpose.

In one or more embodiments of the present invention, a method of operating an actively controlled sealing element (e.g., 600a, 600b) may be based on the tubular (not shown) current within the sealing element (e.g., 600a, 600b). For example, in certain embodiments, one set of seal operating parameters may be used when the drill pipe (not shown) body is disposed within the actively controlled sealing element (e.g., 600a, 600b) and another set of seal operating parameters may be used when the tool joint (e.g., 107) is disposed within the actively controlled sealing element (e.g., 600a, 600b). Advantageously, the runtime of each actively controlled sealing element (e.g., 600a, 600b) may be extended by optimizing the seal operating parameters based on contents to reduce the impact of high wear events on the closed actively controlled sealing element (e.g., 600a, 600b). As with the disclosure of other methods above, the approximate position of the tool joints (e.g., 107) in relation to the actively controlled sealing elements (e.g., 600a, 600b) must be known and may utilize any of the above-disclosed techniques to determine their relative positions. As disclosed previously, one or more sensors (not shown), tool joint position tracking, or combinations thereof may be used to indicate the approximate position of the tool joints (e.g., 107) in relation to the actively controlled sealing elements (e.g., 600a, 600b). However, in contrast to previously disclosed methods, the proximity of the tool joint (e.g., 107) in relation to the actively controlled sealing element (e.g., 600a, 600b) triggers a change in the seal operating parameters from being optimal for sealing on the drill pipe body (e.g., non-tool joint portions of drill string 106) to being optimal for sealing on the tool joint (e.g., 107).

Controlling the parameterization of an actively controlled sealing element (e.g., 600a, 600b) based on the tubular contained within the element (e.g., 600a, 600b) may be accomplished by effecting a desired state on the actively controlled sealing element (e.g., 600a, 600b) based on the information derived by the one or more sensors (not shown) or depth tracking system (not shown). An example of this process is described here using a single non-rotating actively controlled sealing element (e.g., 600a, 600b) based ACD annular sealing system (e.g., 400), however it can be appreciated that the process may be applied to any number of actively controlled sealing elements (e.g., 600a, 600b) being operated not in conjunction with other elements.

Prior to initializing an installed actively controlled sealing element (e.g., 600a, 600b), it may be determined whether or not a tool joint (e.g., 107) is disposed within the actively controlled sealing element (e.g., 600a, 600b). Disposition of the drill pipe body within the actively controlled sealing element (e.g., 600a, 600b) represents a first condition in which a first set of operational seal parameters may be applied. Disposition of the tool joint (e.g., 107) within the seal element (e.g., 600a, 600b) represents a second condition in which a second set of operational seal parameters may be applied. For example, it may be determined that the drill pipe body is disposed within the sealing element (e.g., 600a, 600b) initially and an operator may apply a first higher closing pressure to the actively controlled sealing element (e.g., 600a, 600b). As the drill string (e.g., 106) is moved into or out of the hole, a tool joint (e.g., 107) or other upset feature of the drill string (e.g., 106) approaches the actively controlled sealing element (e.g., 600a, 600b). In anticipation of the tool joint (e.g., 107) making contact with the actively controlled sealing element (e.g., 600a, 600b), the operator may apply a second lower closing pressure to the actively controlled sealing element (e.g., 600a, 600b) optimal for sealing on the tool joint (e.g., 107). While the first condition is true and the second set of parameters are applied, it is possible that fluid leaks from a higher pressure source on one side of the actively controlled sealing element (e.g., 600a, 600b) to a lower pressure source on the other side of the actively controlled sealing element (e.g., 600a, 600b). Leakage of fluid is allowable as long as the average pressure of the well does not change. This may be accomplished through precise control of the MPD choke manifold (e.g., 114). When the tool joint (e.g., 107) enters the actively controlled sealing element (e.g., 600a, 600b), the lower actively controlled sealing element (e.g., 600b) closing pressure may be optimal for sealing on the tool joint (e.g., 107), thereby preventing excessive wear. As the tool joint (e.g., 107) exits the sealing element, the first set of optimal parameters may be applied once again. This approach allows the impact of the tool joint (e.g., 107) entry into or presence of a tool joint (e.g., 107) within an Actively controlled sealing element (e.g., 600a, 600b) to be minimized.

One of ordinary skill in the art, having the benefit of this disclosure, will appreciate that one or more of the above-disclosed methods may be performed in conjunction with other methods including sequential activation and multi-element activation in accordance with one or more embodiments of the present invention. Further, one of ordinary skill in the art will recognize that rotating sealing elements may be used in place of actively controlled sealing elements in certain applications or designs based on one or more embodiments of the present invention. Finally, one of ordinary skill in the art will recognize that methods of tracking the relative position of tool joints with respect to actively controlled sealing elements may vary based on an application or design in accordance with one or more embodiments of the present invention. Furthermore, for illustration, the methods described herein have been described from the perspective of a human operator or programmed control system. In either case, the position of the tool joints relative to the sealing elements is determined and the sealing elements are manipulated to achieve the desired movement of the drill string and/or tool joints in a manner than enhances seal life.

FIG. 10 shows a control system 1000 in accordance with one or more embodiments of the present invention. Control system 1000 may include one or more central processing units (“CPU”) 1005, one or more graphics processing units (“GPU”) 1010, and one or more specialized processing engines 1015. Computing system 1000 may optionally include, if not integrated into CPU 1005, a chipset 1020 that incorporates one or more functions previously provided by a legacy host bridge (not shown) or input/output (“I/O”) bridge (not shown). In certain embodiments, one or more of the above-noted components may be discrete components. In other embodiments, one or more of the above-noted components, or the functions that they implement, may be integrated into a system-on-chip (“SOC”) 1025. An SOC 1025 design may include a plurality of one or more of the above-noted components disposed on the same physical die (not shown) or disposed within the same mechanical package (not shown). One of ordinary skill in the art will recognize that the one or more CPUs 1005, the one or more GPUs 1010, the one or more specialized processing engines 1015, and chipset 1020 may be integrated, in whole or in part, to reduce the thermal design power (“TDP”), reduce power consumption, reduce chip count, reduce the mechanical footprint, and reduce the complexity of the printed circuit board (“PCB”) (not shown) that they may be disposed on.

Each of the one or more CPUs 1005, the one or more GPUs 1010, the one or more specialized processing engines 1015, and chipset 1020 may be a single-core processor (not independently illustrated) or a multi-core processor (not independently illustrated). Multi-core processors typically include a plurality of processor cores (not shown) disposed on the same physical die (not shown) or disposed within the same mechanical package (not shown) that are arranged to provide enhanced capabilities over a single-core implementation. Each of the one or more CPUs 1005 may include a memory interface 1030 to system memory 1035, a graphics interface 1040 to the one or more GPUs 1010, a specialty interface 1013 to the one or more specialized processing engines 1015, and a chipset interface 1045 to chipset 1020. Each of the one or more GPUs 1010 may include a CPU interface 1040 to the one or more CPUs 1005, a memory interface 1050 to graphics memory 1055, and a display interface 1060 to a display device 1065. Chipset 1020 may include a chipset interface 1045 to the one or more CPUs 1005, a memory interface 1070 to system memory 1035, and one or more IO interfaces to one or more IO expansion devices, including, for example, a human/machine interface (“HMI”) interface 1075 to one or more HMI devices 1077, a local storage interface 1079 to one or more local storage devices 1081, a network interface 1083 to one or more network interface devices 1085, and other I/O interfaces 1087 to one or more other I/O devices 1089.

Each local storage device 1081 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. Computing system 1000 may also include one or more network-attached storage devices 1091 that communicate with one or more network interface devices 1085 via a network interface 1085. The one or more network-attached storage devices 1091 may be used in addition to, or instead of, the one or more local storage devices 1081. The one or more network-attached storage devices 1091 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. The one or more network-attached storage devices 1091 may or may not be collocated with control system 1000 and may be accessible to control system 1000 via one or more network interfaces 1083 provided by one or more network interface devices 1085. Each network interface device 1085 may provide one or more network interfaces including, for example, Ethernet, Fiber Channel, WiMAX, Wi-Fi, Bluetooth, or any other type or kind of network connectivity and network protocol suitable for networked communications.

Control system 1000 may also include one or more application specific integrated circuits (“ASICs”) that are configured to perform a certain function, such as, for example, hashing (not shown), in a more efficient manner. The one or more ASICs may interface directly with the one or more CPUs 1005, the one or more GPUs 1010, the one or more specialized processing engines 1015, and chipset 1020.

While control system 1000 has been described above as a general purpose computing device, one of ordinary skill in the art will recognize that control system 1000 may be reduced to only those components necessary to perform a desired function or scaled up as needed to meet requirements. As such, any of the above-noted components, or various subsets, supersets, or combinations of functions or features thereof, may be integrated, in whole or in part, or distributed among various devices based on an application, design, or form factor in accordance with one or more embodiments of the present invention. As such, the description of control system 1000 is merely exemplary and not intended to limit the type, kind, or configuration of components that constitute a computing system suitable for performing computing operations.

In certain embodiments, control system 1000 may be implemented as a specialized industrial system, a server, a workstation, a desktop computer, a laptop computer, a netbook, a tablet, a smartphone, a mobile device, and/or any other type or kind of computing system in accordance with one or more embodiments of the present invention. In other embodiments, control system 1000 may be instantiated as a virtual computer (not shown) in a virtual or cloud-based infrastructure such as those provided by, for example, Amazon AWS®, Microsoft Azure®, Google Cloud®, or other cloud computing service providers. In such embodiments, the components of control system 1000 may be distributed in a manner that is transparent, but potentially unknown, to the end user. Advantageously, virtualization provides physical isolation, fault tolerance, redundancy, and automated backup mechanisms that protect the integrity of data stored therein.

One of ordinary skill in the art, having the benefit of this disclosure, will recognize that one or more non-transitory computer-readable media may comprise software instructions that, when executed by a processor, may perform one or more of the above-noted methods in accordance with one or more embodiments of the present invention.

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.