Seal Assembly Life Extension Methods

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.

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.

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.

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.

shows a schematic of a closed-loop hydraulic drilling systemfor drilling an offshore subterranean wellbore. 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 systemprovides fluid communication between the floating vessel (not shown) and components disposed on the seafloor (not shown), including SSBOPthat is in fluid communication with the wellhead (not shown) of wellbore. Upper portionof marine risertypically includes one or more of rig diverter, ball joint, telescopic joint, and termination joint, where telescopic jointarticulates 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 jointis disposed below telescopic joint.

MPD riser jointprovides fluid communication between upper portionand lower portionof marine riser. Lower portionof marine riserprovides fluid communication with wellboreby way of SSBOPthat is typically disposed above the wellhead (not shown) of wellbore. From the drilling rig (not shown), drill stringis disposed through the central lumen of upper portionof marine riser, MPD riser joint, lower portionof marine riser, SSBOP, and into wellbore. The distal end of drill stringincludes a bottomhole assembly including drill bitfor drilling wellbore. MPD riser jointis typically assembled onshore and delivered to the drilling rig (not shown) as an integrated joint for deployment. MPD riser jointtypically includes annular sealing systemdisposed above, and in fluid communication with, annular closing system. Annular closing systemis disposed above, and in fluid communication with, flow diverter. Flow diverteris disposed above, and in fluid communication with, lower portionof marine riser.

In the description that follows, annular sealing systemmay be National Oilwell Varco's commercial ACD annular sealing system that seals annulussurrounding drill string, creating an annular seal on the wellbore. 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 systemis purpose built for deepwater use and may be offered as a riser joint that integrates with the riser string below the termination joint. Annular sealing systemuses one or more independent, retrievable, and actively controlled sealing elements (not shown) that are controlled by control systemdisposed on the surface of the drilling rig (not shown). Annular closing systemtypically serves as a redundant annular seal that may be engaged when annular sealing system, or components thereof, are being installed, serviced, removed, or otherwise disengaged. Flow diverterdiverts returning fluids from annulus, below the annular seal established by annular sealing system, to the drilling rig (not shown). Flow diverteris in fluid communication with distribution manifoldthat is in fluid communication with one or more choke valves of MPD choke manifold, disposed on the surface of the drilling rig (not shown). MPD choke manifoldis in fluid communication with one or more of mud-gas separator, shale shaker, 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 systemthat sources drilling fluids for one or more mud pumps. During drilling operations, the one or more mud pumpsmay controllably inject drilling fluids (not shown) into an interior passageway (not shown) of drill stringfor operative use.

During conventional drilling operations, control systemmay 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 systemmay control the flow rate of mud pumps, thereby controlling the injection rate of fluids downhole. In addition, control systemmay command one or more choke valves of MPD choke manifoldto a desired choke aperture setting, thereby controlling the flow rate and the application of surface back pressure.

The pressure tight seal on annulusprovided by annular sealing systemallows for the control of wellbore pressure by manipulation of the choke aperture of one or more choke valves of MPD choke manifoldon the surface and the corresponding application of surface back pressure. The choke aperture of MPD choke manifoldcorresponds to an amount, typically represented as a percentage, that MPD choke manifoldis open and capable of flowing. For example, each choke valve of MPD choke manifoldmay 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 wellborepressure, the choke aperture of MPD choke manifoldmay be reduced to further restrict fluid flow and apply additional surface back pressure. Similarly, if the choke operator wishes to decrease wellborepressure, the choke aperture of MPD choke manifoldmay be increased to increase fluid flow and reduce the amount of applied surface back pressure. As such, an important function of MPD riser jointis the creation of the annular seal that facilitates management of wellbore pressure through manipulation of the choke aperture of MPD choke manifold. In this way, wellbore pressure may be managed by manipulating the flow rates of mud pumpsand the application of surface back pressure by manipulation of the choke aperture of MPD choke manifold.

shows an integrated MPD riser jointincluding annular sealing system, annular closing system, and flow diverter. Annular sealing systemis disposed below the bottom distal end of the outer barrel (not shown) of the telescopic joint (not shown). Annular closing systemis disposed directly below annular sealing systemand provides a redundant seal. Flow diverteris disposed directly below annular closing systemand diverts fluids (not shown) from below the annular seal to the surface (not shown). Annular sealing systemseals 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 systemincludes upper annular packer systemand lower annular packer systemeach of which are independently capable of sealing the annulus (not shown) surrounding the drill string (not shown). The redundant combination of annular sealing systemand annular closing systemfurther 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 systemrequires replacement while the marine riser (not shown) is pressurized, such as, for example, during hole sections in between bit runs, annular closing systemmay be engaged to maintain annular pressure while the actively controlled sealing elements (not shown) are disengaged and annular sealing systemis taken offline.

shows a cross-sectional perspective view of an actively controlled sealing elementof an annular sealing system. Actively controlled sealing elementincludes upper metallic end capa substantially cylindrical-shaped wear-resistant seal insertco-molded with buffer material, and lower metallic end capIn the disengaged state, actively controlled sealing elementincludes a central lumenhaving 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 elementof annular sealing systemdoes not rotate with the drill string (not shown). When actively controlled sealing elementis engaged, wear-resistant seal insertflexes and makes contact with the drill string (not shown) and provides critical wear resistance as the drill string (not shown) rotates. Buffer materialsupports wear-resistant seal insertand provides a limited secondary seal in the event seal insertis worn. However, when seal insertis worn, as discussed in more detail herein, buffer materialtends to wear very quickly with rotation of the drill string (not shown). Wear-resistant seal insertincludes 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.

Continuing,shows a cross-sectional elevation view of actively controlled sealing elementof annular sealing system. Wear-resistant seal insertis 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. During the co-molding process, upper metallic end capis attached to the top distal end of seal insertand lower metallic end capis attached to the bottom distal end of seal insert. The insertwith end capsattached 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, end capsand 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 materialis typically composed of polyurethane, nitrile, acrylonitrile butadiene rubber (“NBR”), hydrogenated acrylonitrile butadiene rubber (“HNBR”), or other elastomer material. Notwithstanding, the material composition of seal insertand buffer materialmay vary based on an application or design.

Continuing,shows a hybrid cross-sectional view of a dual seal sleevefor use as part of an annular sealing system (e.g.,). In some applications, the annular sealing system (e.g.,) may use a dual seal sleeveincluding upper actively controlled sealing elementand lower actively controlled sealing elementdisposed on mandrel. Dual seal sleevemay include upper end piece, upper actively controlled sealing elementmandrel, vented intermediate spacer, lower actively controlled sealing elementand lower end piece. Dual seal sleeveincludes a central lumenthat extends through the longitudinal length of sleevethrough which the drill string (not shown) may be disposed. When upper actively controlled sealing elementand lower actively controlled sealing elementare engaged (not shown), a cavity (not independently illustrated) may be formed between them that encompasses the inner area of vented intermediate spacer. 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.,) and the lower annular packer system (e.g.,) of the annular sealing system (e.g.,) are configured to engage upper actively controlled sealing elementand lower actively controlled sealing elementrespectively 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 elementand lower actively controlled sealing elementBecause of the rotation of the drill string (not shown) and the imperfect seal formed by actively controlled sealing elementsandthe injected lubrication fluid (not shown) that lubricates the lower actively controlled sealing elementmay eventually work its way below lower actively controlled sealing elementand 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 elementmay be collected in the trip tank (not shown).

Continuing,shows a hybrid cross-sectional view of independent seal sleevesandfor use as part of an annular sealing system (e.g.,). In some applications, the annular sealing system (e.g.,) may use independent seal sleevesandeach of which include an actively controlled sealing elementorthat are disposed on their own respective mandrelorIndependent seal sleeveincludes first spacer portiondisposed on an upper distal end of actively controlled sealing elementand second spacer portiondisposed on the lower distal end of actively controlled sealing elementSimilarly, independent seal sleeveincludes first spacer portiondisposed on an upper distal end of actively controlled sealing elementand second spacer portiondisposed on a lower distal end of actively controlled sealing elementIndependent seal sleevesandare completely independent from one another. As such, in contrast to the use of a dual seal sleeve (e.g.,), independent seal sleevesandmay be independently engaged or disengaged and independently moved in between bit runs while the annular sealing system (e.g.,) maintains the pressure tight seal on the annulus (not shown). This permits upper actively controlled sealing elementto be retrieved independently with a single run of a running tool or, once upper actively controlled sealing elementhas been removed, lower actively controlled sealing elementmay be retrieved independently with a single run of the running tool, all while maintaining annular pressure. However, both actively controlled sealing elementsandcould potentially be retrieved with a single run of a running tool (not shown).

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

In certain applications, upper actively controlled sealing elementand lower actively controlled sealing elementare engaged at the same time to provide a redundant seal. For reasons beyond the scope of this disclosure, one of upper actively controlled sealing elementor lower actively controlled sealing elementmay wear at a faster rate than the other (typically upper actively controlled sealing element). If one of upper actively controlled sealing elementor lower actively controlled sealing elementwears out in between bit runs, the worn actively controlled sealing elementormust 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 elementsandand be able to replace one or more of worn actively controlled sealing elementorwithout depressurizing the marine riser (not shown), thereby minimizing non-productive downtime and safely maintaining pressure.

shows an elevation view of ACD annular sealing system. Annular sealing systemincludes upper annular packer systemdisposed above lower annular packer systemLubrication injection portis disposed between upper annular packer systemand lower annular packer systemand is configured to inject lubrication fluid (not shown) into the lubrication chamber (not shown) formed there between. Continuing,shows a hybrid cross-sectional elevation view of annular sealing system. Annular sealing systemincludes a central lumenthat extends the longitudinal length of annular sealing system. While upper annular packer(and upper actively controlled sealing element) and lower annular packer(and lower actively controlled sealing element) 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 chamberis formed between upper annular packerand lower annular packer

shows a hybrid cross-sectional elevation view of ACD annular sealing systemwith a dual seal sleeve (e.g.,) disposed within central lumenand operatively positioned within upper annular packer systemand lower annular packer systemCentral lumenmay have a diameter suitable to receive the dual seal sleeveor independent seal sleeves (e.g.,or). The seal sleeves (e.g.,or) may be disposed within annular sealing systemand secured in place with a plurality of upper locking dogsand a plurality of lower locking dogsthat extend radially inward.

At the start of an operation requiring an annular seal on the wellbore (e.g.,), the rig crew uses the surface based control system (e.g.,) to extend a plurality of lower locking cylinderswhich extend radially into the central bore of the housing of annular sealing system. This plurality of lower locking cylindersact as a landing shoulder to properly place dual seal sleevewithin the central bore of the housing of annular sealing system. Once the plurality of lower locking cylindersare fully extended, the rig crew runs dual seal sleevefrom the surface into the housing of ACD. Once dual seal sleevehas landed on the plurality of lower locking cylindersthe rig crew uses the surface based control system (e.g.,) to close a plurality of upper locking cylinderslocated just above the top of dual seal sleeve. The plurality of upper locking cylindersacts to contain dual seal sleevein place once pressure is applied to it. With dual seal sleevelanded in place and the plurality of upper locking cylinders and the plurality of lower locking cylinders engaged, upper intermediate upper locking cylindersand intermediate lower locking cylindersmay be engaged to mechanically isolate upper actively controlled sealing elementand lower actively controlled sealing elementOnce dual seal sleeveis locked in place, the rig crew uses the surface based control system (e.g.,) to actuate upper annular packer systemand lower annular packer systemto engage upper actively controlled sealing elementand lower actively controlled sealing elementOnce locked in place, dual seal sleevedoes not move axially up or down.

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

Continuing,shows a detailed hybrid cross-sectional elevation view of upper actively controlled sealing elementdisposed within upper annular packer systemof annular sealing system. In dual seal sleeveembodiments, the size, shape, and configuration of mandreland vented intermediate spacermay vary to ensure that upper Actively controlled sealing elementis properly positioned within upper annular packer systemIn independent seal sleeves (e.g.,) embodiments, the size, shape, and configuration of the mandrels (e.g.,) for the upper independent seal sleeve (e.g.,) may vary to ensure that upper actively controlled sealing elementis properly positioned within upper annular packer system

Continuing,shows a detailed hybrid cross-sectional elevation view of lower Actively controlled sealing elementdisposed within lower annular packer systemof annular sealing system. In dual seal sleeveembodiments, the size, shape, and configuration of mandreland vented intermediate spacermay vary to ensure that lower actively controlled sealing elementis properly positioned within lower annular packer systemIn independent seal sleeves (e.g.,) embodiments, the size, shape, and configuration of the mandrels (e.g.,) for the lower independent seal sleeve (e.g.,) may vary to ensure that lower actively controlled sealing elementis properly positioned within lower annular packer system

shows a cross-sectional detailed view of actively controlled sealing elementordisposed within an annular packer systemorof an annular sealing system (e.g.,), where annular packeroris in a disengaged state. Upper annular packer systemincludes a piston-actuatedannular packerdisposed within arcuate housingAnnular packeris composed of an elastomer or rubber body with a plurality of fingers, or protrusions,that are configured to travel within arcuate housingwhen pistonis actuated. Actively controlled sealing elementincludes a central lumenthrough which drill string, or portions thereof, may pass therethrough. Similarly, lower annular packer systemincludes a piston-actuatedannular packerdisposed within arcuate housingAnnular packeris composed of an elastomer or rubber body with a plurality of fingers, or protrusions,that are configured to travel within arcuate housingwhen pistonis actuated. Actively controlled sealing elementincludes a central lumenthrough which drill string, or portions thereof, may pass therethrough.

Continuing,shows a cross-sectional detailed view of actively controlled sealing elementordisposed within an annular packer systemorof an ACD-type annular sealing system (e.g.,), where annular packeroris in an engaged state. Actively controlled sealing elementsorare not normally in sealing engagement with drill stringdisposed 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 elementsormust be engaged by spherical annular packersorthat, when actuated, travel within arcuate hosingorsuch that annular packerorcome into contact with and squeeze a middle portion of actively controlled sealing elementorsuch that they form an interference fit with drill stringdisposed therethrough. Annular packersresist deformation such that the application of a lower hydraulic closing pressure causes the ID of the central bore of annular packersto constrict to a lesser degree while a higher hydraulic closing pressure causes the ID of the central bore of annular packerto constrict to a greater degree. From a fully relaxed state, increasing the hydraulic closing pressure acting on pistoncauses annular packerto deform and annular packermaterial in the central bore makes contact with the OD of the seal sleeve (e.g.,,). Continued application of closing pressure increasingly deforms annular packercausing the seal sleeve (e.g.,,) to deform into an hourglass shape. The externally applied force causes the seal insert (e.g.,) to deflect radially inward until it contacts the drill string, creating the annular seal. As such, actively controlled means that sealing elementsorare only engaged while actuation is applied, and once actuation is removed, sealing elementsordisengage. 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 elementor

For example, when hydraulically actuated, pistontravels causing the elastomer or rubber portion of annular packerto travel within arcuate housingsuch that annular packerand fingerscome into contact with upper actively controlled sealing elementWhen annular packeris sufficiently actuated, upper actively controlled sealing elementsqueezes on drill string, such that wear-resistant seal insertand buffer materialcome into contact with a circumference of a portion of drill string, resulting in a pressure tight interference fit surrounding drill string. Whether engaged or not, upper actively controlled sealing elementremains stationary while drill stringrotates. Similarly, when hydraulically actuated, pistontravels causing the elastomer or rubber portion of annular packerto travel within arcuate housingsuch that annular packerand fingerscome into contact with lower actively controlled sealing elementWhen annular packeris sufficiently actuated, lower actively controlled sealing elementsqueezes drill string, such that wear-resistant seal insertand buffer materialcome into contact with a circumference of a portion of drill string, resulting in a pressure tight interference fit surrounding drill string. Whether engaged or not, lower actively controlled sealing elementremains stationary while drill stringrotates.

In dual seal sleeve embodiments, after landing the dual seal sleeve (e.g.,) within the annular sealing system (e.g.,), an annular seal (not shown) may be created by engaging upper annular packerand/or lower annular packerto engage upper actively controlled sealing elementand/or lower actively controlled sealing elementrespectively. The extent to which pistonsare actuated is controlled by the injection of hydraulic power fluid into the actuation chamber (not shown) of pistonsAs such, the amount of closing pressure exerted on actively controlled sealing elementsmay be controlled by the injection of hydraulic power fluid into the actuation chamber (not shown) of pistonsThus, the drilling rig (not shown) may provide sufficient closing pressure to ensure that actively controlled sealing elementsform 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 elementswear.

shows a hybrid cross-sectional view of an actively controlled sealing elementof an annular sealing system (e.g.,) in an unworn state. Seal insertand buffer materialare in a substantially new condition such that, when engaged, seal insertand buffer materialmake contact, and form an interference fit with, the drill string (not shown).

Continuing,shows a hybrid cross-sectional view of an actively controlled sealing elementof the ACD annular sealing system (e.g.,) in a partially worn state. Over time, due to sustained use, seal insertand buffer materialare partially worn such that insertand buffermaterials are partially worn away in the ID of actively controlled sealing elementUpon removal of actuation pressure, the shape of the central lumenis deformed, often bulbous. Consequently, because of the partially worn state of actively controlled sealing elementthe annular packer system (e.g.,) may require more closing pressure to cause the worn sealing elementto make sufficient closing contact with the drill string (not shown) to maintain the pressure tight annular seal.

Continuing,shows a hybrid cross-sectional view of an actively controlled sealing elementof the annular sealing system (e.g.,) in a further worn state. Wear of actively controlled sealing elementoccurs 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 elementthrough 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 elementExcess 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 elementAbrasion is common where the pressure differential between the fluids above and below each actively controlled sealing elementis low and the fluid flow across each actively controlled sealing elementis negligible. Erosion of the annular seal is caused by the high speed collision of fluid particles with actively controlled sealing elementWear due to erosion may occur where the pressure differential between the fluids above and below each actively controlled sealing elementis high and the fluid flow across the element is not negligible. Both erosion and abrasion remove material from actively controlled sealing elementfrom the interface between the drill pipe (not shown) and actively controlled sealing element

Continued use of the partially worn actively controlled sealing elementcauses further wear to seal insertand buffer materialsuch that the shape of the central lumenis even more deformed, usually bulbous. Consequently, because of the substantially worn state of sealing elementthe annular packer system (e.g.,) may require even more hydraulic actuation to provide sufficient closing pressure that causes the substantially worn actively controlled sealing elementto make sufficient closing contact with the drill string (not shown) to maintain the pressure tight annular seal.

Continuing,shows a hybrid cross-sectional view of an actively controlled sealing elementof the ACD annular sealing system (e.g.,) in a worn state. Eventually, seal insertis breached approximately at its midpoint, leaving a band of exposed elastomer buffer materialin contact with the drill string (not shown). Due to the bending of seal insertby external pressure, seal insertcontinues to support the elastomer buffer materialeven after the initial breach. With continued use, the support of the remaining seal insertis eventually lost. When this occurs, the annular packer (e.g.,) pushes on the unsupported buffer materialWithout the support of seal insertthe annular packer system (e.g.,) must close to greater degree to maintain seal integrity on buffer materialContinued use of the substantially worn actively controlled sealing elementcauses further wear to seal insertand buffer materialsuch that a substantial portion of seal insertis fully worn away and the central lumenis even more bulbous and consists primarily of buffer materialConsequently, because of the fully worn state of actively controlled sealing elementthe annular packer system (e.g.,) may require even more hydraulic actuation, if even possible at all, to cause the fully worn sealing elementto make sufficient closing contact with the drill string (not shown) to maintain the annular seal, if even possible at all. In such circumstances, buffer materialmust be relied upon to make the closing contact with the drill string (not shown) in an attempt to maintain the annular seal. However, buffer materialis typically composed of polyurethane and is not wear resistant. While buffer materialwears 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 elementat 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.,), the wall thickness at the middle point of its seal insert (e.g.,) is gradually reduced. Gradual removal of the material from the ID is offset by injecting incrementally more hydraulic fluid into the piston (e.g.,) of the annular packer system (e.g.,) in which it is disposed. Increased actuation causes the piston (e.g.,) to further close on the annular packer (e.g.,), backfilling the material worn from the sealing interface.

For the annular packer system (e.g.,) to close to greater degree, the internal resistance of the annular packer (e.g.,) must also be overcome. The internal resistance of the annular packer (e.g.,) is an important dynamic when considering the hydraulic closing pressure required to seal on various diameters. If the annular packer (e.g.,) must seal against a large OD tubular or a new actively controlled sealing element (e.g.,), less hydraulic closing pressure is required to overcome the internal resistance of the annular packer (e.g.,) itself. If the annular packer (e.g.,) must seal against a small OD tubular or a worn actively controlled sealing element (e.g.,), more hydraulic closing pressure is required to overcome the internal resistance of the annular packer (e.g.,). This dynamic is applied practically in that once the support of the seal insert (e.g.,) is lost, a significantly higher amount of hydraulic closing pressure must be applied to the annular packer system (e.g.,) 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.,) supported sealing engagement to sealing engagement without the insert (e.g.,), signifying that the actively controlled sealing element (e.g.,) 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.,) 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.,). Advantageously, this extends the runtime of the actively controlled sealing elements (e.g.,) by preventing the passage of a tool joint (not shown) or other feature through closed non-rotating actively controlled sealing elements (e.g.,) to prevent excessive wear of actively controlled sealing elements (e.g.,). This process of coordinating the activation of actively controlled sealing elements (e.g.,) may be performed manually by a human operator or automatically using a control system (e.g.,). In order to coordinate the activation of actively controlled sealing elements (e.g.,) 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.,), 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.,) and 2) determine the approximate location of the actively controlled sealing elements (e.g.,). With this information, we may coordinate the activation of actively controlled sealing elements (e.g.,) with the transiting of tool joints (not shown). Advantageously, the operational life of actively controlled sealing elements (e.g.,) 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.,) may use one or more sensors (not shown) that directly measure qualities of the drill string (e.g.,) in the vicinity of the sensors (not shown). One or more sensors (not shown) measuring qualities of the drill string (e.g.,) may be disposed parallel to the main bore axis at or near the landed location of each actively controlled sealing element (e.g.,). The sensors (not shown) transmit sensor data to the control system (e.g.,), 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.,), 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.,) and preferentially above and below each of the actively controlled sealing elements (e.g.,) to detect the approximate position of a tool joint (not shown) within the annular sealing system (e.g.,).

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.,) is to track approximate positions of tool joints (not shown) indirectly from existing instrumentation available on a modern drilling rig (not shown).