BACKGROUND OF THE INVENTION

[0001] 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, the hydrostatic pressure at the bottom of the wellbore is determined by the weight of the fluid column and varies based on the density of the fluid and depth of the well. To drill ahead, the rig must circulate drilling fluids to lubricate the drillbit, remove cuttings, and maintain wellbore stability. However, as the flow rate increases, the interaction of fluid particles with the wellbore, drillstring, and other fluids introduces frictional pressures. This friction causes the bottom hole pressure to increase as a function of the flow rate. While the friction acting at depth may be reduced by optimizing the fluid composition, flow rate, or tubular design, there is no way to completely eliminate friction from the well system. As such, the bottom hole pressure is substantially equal to the hydrostatic pressure of the fluid column when the mud pumps are turned off, but they are much higher when the mud pumps are turned on and flowing due to friction.

[0002] Under conventional drilling practices, forward drilling progress may only be made so long as the wellbore pressure is maintained in a range between the pore pressure and the fracture pressure, sometimes referred to as the drilling margin. If the static wellbore pressure falls below the pore pressure, there is a substantial risk of taking an influx of unknown formation fluids into the well system, sometimes referred to as a kick, that may include dangerous and explosive gases. If the dynamic wellbore pressure exceeds the fracture pressure, the formation may fracture, resulting in the loss of expensive drilling fluids downhole and potentially loss of well control. While drillers attempt to carefully thread the needle by maintaining wellbore pressure within the drilling margin, under conventional drilling practices, this is achieved through the careful composition of the drilling fluids that are used. If the pressure falls outside the drilling margin, contingencies may arise, including a dangerous blowout. As such, under conventional drilling practices, the driller must carefully maintain the drilling fluid composition such that the static wellbore pressure is greater than the pore pressure and the dynamic wellbore pressure is less than the fracture pressure of the formation, for every open hole formation, simultaneously. When it is not possible to do this with a single drilling fluid, the rig must stop drilling and a casing must be set to protect vulnerable formations. [0003] In applied surface back pressure (“ASBP”) managed pressure drilling (“MPD”) operations, a rotating control device (“RCD”), active control device (“ACD”), or other type of annular sealing system is used to seal the annulus surrounding the drillpipe above the blowout preventer (“BOP”) such that the wellbore is not atmospheric. Drilling returns are diverted from the annulus below the annular seal to a dedicated MPD manifold on the rig that typically includes an array of sensors for measuring pressure, temperature, and flow rate of fluids as well as one or more variable choke valves and a control system that controls the position of the choke. While the rig is circulating fluids through the drillstring, the choke is at least partly or mostly open to maintain a lower fluid pressure at the surface. As circulation is stopped, the choke is moved to a more closed position to achieve a higher fluid pressure at the surface. Because pressure applied to the wellbore from the surface increases the bottom hole pressure by an equal amount, wellbore pressure may therefore be controlled by the application of pressure at the surface. In this way, surface back pressure is applied through the controlled aperture setting of one or more chokes of the MPD manifold.

[0004] While there is no way to completely eliminate friction from the well, the use of ASBP-MPD techniques allows the driller to trade surface back pressure for downhole circulation friction as the flow rate through the well varies, thereby allowing the rig to stabilize the downhole pressures and maintain a constant downhole pressure at a defined depth. As drilling margins get tighter and tighter, this ability to precisely control wellbore pressure is critically important to drilling operations and the safety of the rig personnel. Because MPD operations require a pressure-tight annular seal, that blocks the flow of drilling fluids and allows for the controlled application of surface back pressure, it is critically important that the annular sealing system functions to maintain pressure at all times. However, annular sealing systems typically include wearable sealing elements that wear and eventually fail, giving rise to extremely dangerous contingencies.

BRIEF SUMMARY OF THE INVENTION

[0005] According to one aspect of one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element includes applying an external energy source to actuate the sealing element to form an interference fit with a pipe member disposed through a lumen of the sealing element, actively controlling the application of the external energy source to maintain the sealing element’s interference fit with the pipe member, collecting process control data at predetermined intervals, determining for each predetermined interval, a raw value of energy absorbed by the sealing element based at least in part on the collected process control data, and providing an indication of the raw value of energy being absorbed by the actively controlled sealing element.

[0006] According to one aspect of one or more embodiments of the present invention, a non-transitory computer-readable medium comprising software instructions that, when executed by a processor, performs a method of predictive wear state modeling for an actively controlled sealing element that includes applying an external energy source to actuate the sealing element to form an interference fit with a pipe member disposed through a lumen of the sealing element, actively controlling the application of the external energy source to maintain the sealing element’s interference fit with the pipe member, collecting process control data at predetermined intervals, determining, for each predetermined interval, a raw value of energy absorbed by the sealing element based at least in part on the collected process control data, and providing an indication of the raw value of energy being absorbed by the actively controlled sealing element..

[0007] Other aspects of the present invention will be apparent from the following description and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0008] FIG. 1 shows a block diagram of a conventional deepwater MPD drilling system with an ACD annular sealing system.

[0009] FIG. 2A shows an elevation view of an ACD annular sealing system.

[0010] FIG. 2B shows a cross-sectional view of the ACD annular sealing system in a disengaged state.

[0011] FIG. 3 A shows a cross-sectional perspective view of a seal assembly of an ACD annular sealing system.

[0012] FIG. 3B shows a cross-sectional view of the seal assembly of the ACD annular sealing system.

[0013] FIG. 4A shows a cross-sectional view of an annular packer system of an ACD annular sealing system with drillpipe disposed therein and the annular packer element in a disengaged state.

[0014] FIG. 4B shows a cross-sectional view of the annular packer system of the ACD annular sealing system with drillpipe disposed therein and the annular packer element in an engaged state.

[0015] FIG. 5A shows a cross-sectional view of an actively controlled sealing element of a seal assembly of an ACD annular sealing system in a new and unworn state. [0016] FIG. 5B shows a cross-sectional view of the actively controlled sealing element of the seal assembly of the ACD annular sealing system in a partially worn state.

[0017] FIG. 5C shows a cross-sectional view of the actively controlled sealing element of the seal assembly of the ACD annular sealing system in a substantially worn state.

[0018] FIG. 5D shows a cross-sectional view of the actively controlled sealing element of the seal assembly of the ACD annular sealing system in a fully worn state.

[0019] FIG. 6 shows an exemplary plot of closing pressures, lubrication pressure, and wellbore pressure of an ACD annular sealing system used to predict the end of design life of the actively controlled sealing elements of the seal assemblies.

[0020] FIG. 7A shows an exemplary plot of raw values of absorbed energy by an actively controlled sealing element versus hours of seal usage in accordance with one or more embodiments of the present invention.

[0021] FIG. 7B shows an exemplary plot of adjusted values of absorbed energy by an actively controlled sealing element versus hours of seal usage in accordance with one or more embodiments of the present invention.

[0022] FIG. 8 shows a computing system in accordance with one or more embodiments of the present invention.

[0023] FIG. 9 shows a programmable logic device system in accordance with one or more embodiments of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

[0024] 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.

[0025] In onshore MPD applications, a conventional RCD-type annular sealing system is typically used to create the annular seal. The RCD system is installed above the BOP and below the rig floor. The RCD system includes a housing, a seal assembly removably disposed within the housing, and one or more fluid ports that discharge fluids from the annulus formed between the seal assembly and the housing, below the annular seal formed therein. The seal assembly typically includes a bearing assembly that has a rotating inner portion and a static outer portion that does not move relative to the housing. The rotating inner portion includes a plurality of passive sealing elements having a central lumen through which drillpipe and tool joints may pass. The passive sealing elements have an outer diameter that is smaller than the outer diameter of the drillstring at its smallest point that form an interference fit with drillpipe disposed therethrough. One or more rotary seals are used to seal between the static outer portion and the rotating inner portion of the bearing assembly. One or more static outer diameter seals are used to prevent the flow of fluids around the bearing assembly.

[0026] In operation, the passive sealing elements conform to the drillpipe disposed therethrough creating a seal that flexes as the outer diameter of the drillstring changes due to axially movement. The rotating inner portion allows the passive sealing elements to rotate with the drillstring to reduce wear. This configuration of sealing elements forms the annular seal that prevents the upward flow of fluids, which are discharged through the one or more fluid ports of the RCD to the MPD manifold on the rig. This allows the rig to apply back pressure from the surface through the control of the aperture setting, or position, of the one or more choke valves of the MPD manifold. One drawback to the use of conventional RCD-type annular sealing systems is that the failure of a passive sealing element, rotary seal, or outer diameter seal breaks the pressure tight seal on the annulus, requiring retrieval and replacement of the seal assembly. Another drawback is that there is no reliable method to determine the remaining life of the sealing elements or the seal assembly. Notwithstanding, due to the compact design, RCD-type annular sealing systems are commonly used on drilling rigs with limited clearance under the rig floor, such as land-based rigs, offshore jack up rigs, and offshore platform rigs.

[0027] While deepwater drilling has much in common with onshore and shallow water drilling, deepwater presents a unique set of challenges that limit the effectiveness of RCD-type annular sealing systems. Presence of unconsolidated or uncompacted sediments in deepwater drive the need for additional casing strings increasing the inner diameter required of the subsea blowout preventer (“SSBOP”) and riser. Larger diameter hole sections require higher flow rates and larger pipe with correspondingly different hydraulic characteristics to maintain suitable hole cleaning conditions. Larger pipe also uses larger tool joints which require greater clearance through the inner diameter of a bearing assembly, resulting in higher rotary seal velocities and faster wear for rotary sealing elements. For these reasons and others, the placement of a deepwater RCD-type annular sealing system is typically 100 feet or more below the rig flow. The rig personnel must take great care to protect the static outer diameter seals and sealing surfaces when running and pulling the seal assembly, further complicating the process and requiring additional protective measures at the expense of rig time and increased operating costs.

[0028] The ACD annular sealing system was purpose built to address shortcomings of passive RCD-type annular sealing systems in deepwater applications. In contrast to RCD- type annular sealing systems, the ACD annular sealing system uses a plurality of sealing elements that must be actively engaged by an external energy source and controlled to seal the wellbore annulus. A control system causes a hydraulics system to apply sufficient closing pressure to the sealing elements such that they form an interference fit with drillpipe disposed therethrough and monitor key variables such as the applied closing pressure, fluid flow, or temperature of processes and components within the system. Similar to RCD-type annular sealing systems, the ACD annular sealing system uses wearable sealing elements that have a lifespan that vary significantly based on the operation and conditions of use. However, in contrast to RCD-type annular sealing systems, the wearable sealing elements of the ACD annular sealing system are static when engaged and do not rotate with drillpipe disposed therethrough.

[0029] FIG. 1 shows a block diagram of a conventional deepwater MPD drilling system 100 with an ACD annular sealing system 200. A floating platform or rig (not shown) is typically disposed over a body of water (not shown) to facilitate deepwater drilling and other operations. An SSBOP 110 is disposed above and in fluid communication with the wellhead (not shown) of the wellbore (not shown). A marine riser 115 is disposed above and in fluid communication with SSBOP 110. In conventional below-tension-ring MPD configurations, an MPD flow spool 120 is disposed above and in fluid communication with marine riser 115, an MPD annular closing system 125 is disposed above and in fluid communication with MPD flow spool 120, and an ACD annular sealing system 200 is disposed above and in fluid communication with MPD annular closing system 125. A slip joint 135 is disposed above MPD annular closing system 125 and a diverter and flex joint 140 is disposed above and in fluid communication with slip joint 135. A top drive system 145 controllably provides rotation to a drillstring (not shown) disposed through a central lumen (not shown) that extends from diverter 140 through to the wellbore (not shown).

[0030] In operation, ACD annular sealing system 200 controllably seals the annulus surrounding the drillstring (not shown) such that the annulus is encapsulated and is not exposed to the atmosphere. MPD annular closing system 125 provides an additional controllable seal capable of encapsulating the well and sealing the annulus surrounding the drillstring when rotation has stopped or ACD annular sealing system 200, or components thereof, are being installed, serviced, maintained, removed, or otherwise disengaged. MPD flow spool 120 diverts returning fluids from below the annular seal formed by ACD annular sealing system 200 (or MPD annular closing system 125) to a distribution manifold 150 and MPD manifold 155 disposed on the rig (not shown). MPD manifold 155 directs returning fluids to fluids processing systems disposed on the rig (not shown), such as, for example, shale shakers 160 that process returning fluids for reuse. Shale shakers 160 discharges processed fluids to active mud pit 165. Active mud pit 165 provides drilling fluids to lubrication system 170 that lubricates ACD annular sealing system 200, booster pump 175 that injects drilling fluids into the riser to dilute cuttings, and rig mud pumps 180 that inject drilling fluids into the drillstring (not shown).

[0031] During drilling operations, a control system (not shown) may control the flow rate of mud pumps 180, thereby controlling the injection rate of fluids downhole. In addition, the control system (not shown) may command one or more choke valves of MPD manifold 155 to a desired choke aperture setting, or position, thereby controlling the flow out. As noted above, the pressure tight seal on the annulus provided by ACD annular sealing system 200 allows for the control of wellbore pressure by manipulation of the choke aperture, or position, of one or more choke valves of MPD manifold 155 and the corresponding application of surface backpressure. The choke aperture of MPD manifold 155 corresponds to an amount, commonly represented as a percentage, that MPD manifold 155 is open and capable of flowing. For example, each choke valve of MPD manifold 155 may be fully opened, fully closed, or somewhere in between with a plurality of intermediate settings that refer to some degree of openness. While MPD manifold 155 may include a plurality of chokes, it is common to refer to the plurality of chokes as a singular choke when referring to choke aperture or position of the MPD manifold 155. If the choke operator wishes to increase wellbore pressure, the choke aperture of MPD choke manifold 155 may be reduced to further restrict fluid flow and apply additional surface backpressure. Similarly, if the choke operator wishes to decrease wellbore pressure, the choke aperture of MPD manifold 155 may be increased to increase fluid flow and reduce the amount of applied surface backpressure.

[0032] FIG. 2A shows an elevation view of an ACD annular sealing system 200. ACD annular sealing system 200 may include an upper annular packer system 210a configured to receive an upper seal assembly (not shown) and a lower annular packer system 210b configured to receive a lower seal assembly (not shown). A lubrication injection port 220 may be disposed between upper annular packer system 210a and lower annular packer system 210b and is configured to inject lubrication fluid (not shown) into a lubrication chamber (270 of FIG. 2B) formed between the upper seal assembly (not shown) and the lower seal assembly (not shown).

[0033] Continuing, FIG. 2B shows a cross-sectional view of the ACD annular sealing system 200 in a disengaged state. ACD annular sealing system 200 may include a central lumen 230 that extends through the longitudinal length of ACD annular sealing system 200, having an inner diameter suitable to receive a retrievable seal and mandrel assembly 235. The retrievable seal and mandrel assembly may include an upper seal assembly 300a, a mandrel 340, and a lower seal assembly 300b. The retrievable seal and mandrel assembly 235 may be disposed within a landing profile of ACD annular sealing system 200 and secured in place with a plurality of upper locking dogs 240a and a plurality of lower locking dogs 240b that extend radially inward when engaged, such that upper seal assembly 300a is operatively placed for engagement within upper annular packer system 210a and lower seal assembly 300b is operatively placed for engagement within the lower annular packer system 210b.

[0034] Drillpipe 250 or tool joints (not shown) may be disposed within central lumen 230 through upper annular packer system 210a, upper seal assembly 300a, lower annular packer system 210b, and lower seal assembly 300b. Lubrication fluids (not shown) may be injected through lubrication port 220 into lubrication chamber 270 of retrievable seal and mandrel assembly 235 that buffers the internal surfaces of the seal interfaces. ACD annular sealing systems 200 are purpose built for use in deepwater and typically include a surface-based control system (e.g., 800 of FIG. 8 or 900 of FIG. 9) that connects to the subsea riser joint (not shown) by way of an umbilical system (not shown). ACD annular sealing system 200 may be used standalone or as part of an integrated riser joint (not shown).

[0035] FIG. 3A shows a cross-sectional perspective view of a seal assembly 300 of an ACD annular sealing system 200. Seal assembly 300 includes a rigid metal upper end cap 310a, a sealing element formed by a wear-resistant durable seal insert 320 co-molded with a buffer material 330, and a rigid metal lower end cap 310b. The sealing element formed by durable seal insert 320 and buffer material 330 has an inner diameter that is configured to receive drillpipe e.g., 250 of FIG. 2B) or tool joints (not shown) therethrough. When not engaged, the sealing element formed by durable seal insert 320 and buffer material 330 is substantially cylindrical in shape with an inner diameter that is larger than the outer diameter of drillpipe or tool joints (not shown) with which it will be used. When engaged, the sealing element formed by durable seal insert 320 and buffer material 330 is designed to flex and seal the annulus surrounding the drillpipe (e.g., 250 of FIG. 2B) or tool joint (not shown) disposed therethrough with an interference fit. However, in contrast to the sealing element of an RCD-type annular sealing system, each seal assembly 300 of an ACD-type annular sealing system (not shown) does not rotate with the drillpipe (not shown). When seal assembly 300 is engaged, the sealing element formed by durable seal insert 320 and buffer material 330 makes contact with the drillpipe (e.g., 250 of FIG. 2B) or tool joint (not shown) and provides critical wear resistance as the drillpipe (e.g., 250 of FIG. 2B) rotates. As such, the design and composition of the sealing element formed by durable seal insert 320 and buffer material 330 is key to providing extreme erosion and abrasion resistance.

[0036] Durable seal insert 320 is typically milled from a solid polymer billet to achieve a preferred dimension and is milled radially to form a preferred pattern. Durable seal insert 320 may be milled into a honeycomb, or other matrix pattern, that effectively reduces the stiffness of the matrix and increases the surface area for bonding with buffer material 330. During molding, a top portion of durable seal insert 320 is attached to upper end cap 310a and a bottom portion of durable seal insert 320 is attached to lower end cap 310b. The assembly formed by the durable seal insert 320, upper end cap 310a, and lower end cap 310b is secured in a shaped mold (not shown) and liquid elastomer (not shown) is poured into the mold, filing the void space in the durable seal insert 320 and the void spaces between the insert 320, upper end cap 310a, lower end cap 310b, and the mold. The elastomer material cures in the mold, retaining the shape of the mold once the mold is removed, forming the co-molded sealing element composed of durable seal insert 320 and buffer material 330. Buffer material 330 serves as flexible point of contact with the annular packer system and provides a secondary surface for creating a seal in the event durable seal insert 320 is worn. However, buffer material 330 tends to wear very quickly with continued rotation of the drillpipe (e.g., 250 of FIG. 2B). Continuing, FIG. 3B shows a cross-sectional view of a seal assembly 300 of the ACD annular sealing system 200. In certain embodiments, wear-resistant durable seal insert 320 may be comprised of polytetrafluoroethylene (“PTFE”), ultra-high molecular weight polyethylene, or other polymer-based material that resists wear and buffer material 330 may be comprised of polyurethane, nitrile, acrylonitrile butadiene rubber (“NBR”), hydrogenated acrylonitrile butadiene rubber (“HNBR”), or other elastomer material. [0037] FIG. 4A shows a cross-sectional view of an annular packer system 210 of an ACD annular sealing system (e.g., 200) with drillpipe 250 disposed therein and annular packer element 410 in a disengaged state. Annular packer system 210 may include a piston- actuated 440 annular packer element 410 disposed within a radiused housing 420. Annular packer element 410 may comprise an elastomer or rubber body with a plurality of fingers or protrusions 430 that travel within housing 420 when actuated. Seal assembly 300 includes a central lumen 260 through which drillpipe 250 or tool joints (not shown) may pass.

[0038] Continuing, FIG. 4B shows a cross-sectional view of the annular packer system 210 of the ACD annular sealing system (e.g., 200) with drillpipe 250 disposed therein and the annular packer element 410 in an engaged state. Annular packer system 210 includes an annular packer element 410 disposed within a housing 420. When a control system (not shown) hydraulically actuates piston 440, the movement of piston 440 causes the elastomer or rubber portion of annular packer element 410 to travel within housing 420 such that annular packer element 410 and protrusions 430 thereof come into contact with and cause the sealing element formed by durable seal insert 320 and buffer material 330 to flex. Hydraulic actuation of piston 440 with sufficient closing pressure causes annular packer element 410 to displace the sealing element formed by durable seal insert 320 and buffer material 330 such that the inner diameter of the sealing element constricts around drillpipe 250. The degree with which the inner diameter of the sealing element constricts around drillpipe 250 is proportional to the amount of closing pressure applied to the hydraulic actuation of piston 440. With the application of sufficient closing pressure, the sealing element formed by durable seal insert 320 and buffer material 330 flexes into an hourglass shape that forms a pressure-tight interference fit around drillpipe 250. It is important to note that, whether engaged or not, seal assembly 300 remains stationary while drillpipe 250 rotates. As such, the design of seal assembly 300 anticipates wear to the sealing element during rotation and use. The amount of closing pressure required to form the interference fit and maintain the pressure tight seal on drillpipe 250 varies based on various factors including the wall thickness of the sealing element formed by durable seal insert 320 and buffer material 330, wellbore pressures, and the outer diameter of tubulars in the sealing environment. As the sealing element formed by durable seal insert 320 and buffer material 330 wears, more closing pressure may be required to maintain the pressure tight seal on drillpipe 250. The control system may actively monitor and control the application of closing pressure to ensure the maintenance of the pressure tight seal.

[0039] During operation, the control system (not shown) directs a lubrication system (e.g., 170) on the surface to inject clean drilling fluid into the void space between an upper seal assembly (e.g., 300a) and a lower seal assembly (e.g., 300b) of the retrievable seal and mandrel assembly (e.g., 235 of FIG. 2B) of the ACD annular sealing system (e.g., 200 of FIG. 2B), referred to as the lubrication chamber (e.g., 270 of FIG. 2B). Injection of clean drilling fluids into the lubrication chamber e.g., 270 of FIG. 2B) allows the lubrication chamber pressure to achieve a pressure higher than that of the pressure in the annulus below the lower seal assembly e.g., 300b), verifying that the annulus below the lower seal assembly e.g., 300b) is fully isolated from the annulus above. In addition, the injection of clean drilling fluids prevents the settlement of drilled cuttings within the seal assembly and aids in the safe detection of the end of design life conditions. In this way, variable control of the lubrication system (e.g., 170) and the lubrication pressure provided to the lubrication chamber (e.g., 270 of FIG. 2B) allows for multiple operating modes including constant flow rate drilling and constant pressure stripping.

[0040] FIG. 5A shows a cross-sectional view of an actively-controlled sealing element formed by durable seal insert 320 and buffer material 330 of seal assembly 300 of an ACD annular sealing system (e.g., 200 of FIG. 2B) in a new and unworn state. The sealing element is in a substantially new condition such that, when engaged, the sealing element forms a pressure tight interference fit with drillpipe (e.g., 250 of FIG. 2B). Wear of the sealing element occurs from the inside at the interface between the drillpipe (e.g., 250 of FIG. 2B) and the sealing element. One of the primary contributors to wear of the sealing element is abrasion caused by scraping action of the drillpipe (e.g., 250 of FIG. 2B) as it rotates and reciprocates while in contact with the sealing element. Excess abrasion may occur when rough edges such as hard banding or die mark on tool joints (not shown) pass through the sealing element. Abrasion is common when the pressure differential between fluids above and below the sealing element are low and the fluid flow across the sealing element is negligible. Another primary contributor to wear of the sealing element is erosion caused by the high-speed collision of fluid particles with the sealing element. Wear from erosion typically occurs when the pressure differential between the fluids above and below the sealing element is high and the fluid flow across the sealing element is no longer negligible. In this way, abrasion and erosion remove material from the sealing element at the interface between the drillpipe (e.g., 250 of FIG. 2B) and the sealing element.

[0041] Continuing, FIG. 5B shows a cross-sectional view of the actively-controlled sealing element formed by durable seal insert 320 and buffer material 330 of seal assembly 300 of an ACD annular sealing system (e.g., 200 of FIG. 2B) in a partially worn state. Over time, due to sustained use, the sealing element formed by durable seal insert 320 and buffer material 330 are partially worn such that the shape of the central lumen 260 is somewhat bulbous in the disengaged and relaxed state. When the sealing element formed by durable seal insert 320 and buffer material 330 is engaged, the sealing element tends to flex into an hourglass shape as it forms the interference fit. As such, the sealing element tends to wear more towards the middle, such that, when the sealing element is disengaged, the relaxed shape of the sealing element has a reverse hourglass shape. Consequently, because of the partially worn state of sealing element formed by durable seal insert 320 and buffer material 330 of seal assembly 300, the annular packer system (e.g., 210 of FIG. 2B) may require the application of more closing pressure (via the control system’s hydraulic actuation of piston 440 of FIG. 4B) to flex the worn sealing element of seal assembly 300 enough to make sufficient closing contact with the drillpipe (e.g., 250 of FIG. 2B) and maintain the pressure tight annular seal.

[0042] Continuing, FIG. 5C shows a cross-sectional view of the actively-controlled sealing element formed by durable seal insert 320 and buffer material 330 of seal assembly 300 of an ACD annular sealing system (e.g., 200 of FIG. 2B) in a substantially worn state. Continued use causes further wear to the sealing element formed by durable seal insert 320 and buffer material 330, primarily reducing the thickness of the durable seal insert 320 towards the middle of the sealing element. Consequently, the annular packer system (e.g., 210 of FIG. 2B) may require even more closing pressure (via the control system’s hydraulic actuation of piston 440 of FIG. 4B) to flex the substantially worn sealing element of assembly 300 enough to make sufficient closing contact with the drillpipe (e.g., 250 of FIG. 2B) and maintain the pressure tight annular seal.

[0043] Continuing, FIG. 5D shows a cross-sectional view of the actively-controlled sealing element formed by durable seal insert 320 and buffer material 330 of seal assembly 300 of an ACD annular sealing system (e.g., 200 of FIG. 2B) in a fully worn state. Continued use of the substantially worn seal assembly 300 causes further wear to durable seal insert 320 and buffer material 330 such that a substantial portion of durable seal insert 320 is fully worn away. Once the durable seal insert 320 is breached, approximately at the midpoint of the sealing element, there is a band of exposed buffer material 330 that comes into contact with the drillpipe (e.g., 250 of FIG. 2B). While the remaining portion of the durable seal insert 320 continues to support buffer material 330 even after breach, with continued use, the unsupported portions of buffer material 330 require greater radial force to maintain the pressure tight seal on the drillpipe (e.g., 250 of FIG. 2B). Consequently, because of the fully worn state of seal assembly 300, the annular packer system (e.g., 210 of FIG. 2B) may require even more closing pressure (via the control system’s hydraulic actuation of piston 440 of FIG. 4B), if even possible at all, to cause the fully worn seal assembly 300 to make sufficient closing contact with the drillpipe (not shown) and maintain the annular seal.

[0044] For purposes of this disclosure, closing pressure refers to the minimum amount of hydraulic pressure required to activate a sealing element of a seal assembly (e.g., 300a or 300b of FIG. 2B) of an ACD annular sealing system e.g., 200 of FIG. 2B), such that a sealing element of a seal assembly (e.g., 300a or 300b of FIG. 2B) forms and maintains a pressure tight seal on drillpipe (e.g, 250 of FIG. 2B) disposed therethrough. The lubrication pressure refers to the amount of pressure in the lubrication chamber (e.g., 270 of FIG. 2B) formed between an upper seal assembly (e.g., 300a or of FIG. 2B) and a lower seal assembly (e.g., 300b of FIG. 2B) of the ACD annular sealing system (e.g., 200 of FIG. 2B). In normal operating conditions, the lower seal assembly (e.g., 300b of FIG. 2B) of an ACD annular sealing system (e.g., 200 of FIG. 2B) is typically used to maintain the pressure tight seal on the drillpipe (e.g. , 250 of FIG. 2B) while the upper seal assembly (e.g., 300a of FIG. 2B) is used to control the lubrication pressure in lubrication chamber (e.g., 270 of FIG. 2B), that receives a constant injection of lubrication fluid from the surface, usually clean drilling fluids.

[0045] In the prior art, various monitoring and detection schemes have been developed to determine when a sealing element requires replacement in anticipation of failure. FIG. 6 shows an exemplary plot of closing pressures 605, 610, lubrication pressure 615, and wellbore pressure 620 of an ACD annular sealing system (e.g., 200 of FIG. 2) used to predict the end of design life of the actively-controlled sealing elements of the seal assemblies (e.g., 300a, 300b of FIG. 2B).

[0046] During normal operations, the upper annular packer system (e.g., 210a of FIG. 2B) and the lower annular packer system (e.g., 210b of FIG. 2B) are independently controlled and operated by the control system (e.g., 800 of FIG. 8 or 900 of FIG. 9). In drilling mode, the control system (e.g., 800 of FIG. 8 or 900 of FIG. 9) directs the lubrication system (e.g., 170 of FIG. 1) to inject drilling fluids into the lubrication chamber (e.g., 270 of FIG. 2B) formed between the upper seal assembly (e.g., 300a of FIG. 2B) and the lower seal assembly (e.g., 300b of FIG. 2B) at a constant flow rate. Typically, the lower seal assembly (e.g., 300b of FIG. 2B) is operated to maintain a pressure tight seal on the annulus surrounding drillpipe (e.g., 250 of FIG. 2B), while the upper seal assembly (e.g., 300a of FIG. 2B) is operated to control the lubrication pressure 615. As such, the sealing element of the upper seal assembly (e.g. , 300a of FIG. 2B) tends to wear by erosion while the sealing element of the lower seal assembly (e.g., 300b of FIG. 2B) tends to wear more from abrasion. Notably, these wear mechanisms remove material from a sealing element at different rates. Under normal operating conditions, the sealing element of the upper seal assembly (e.g., 300a of FIG. 2B) tends to wear faster than the sealing element of the lower seal assembly (e.g., 300b of FIG. 2B).

[0047] Assuming constant closing pressure 605 is applied to the lower annular packer system (e.g., 210b of FIG. 2B) and substantially equal constant closing pressure 610 is applied to the upper annular packer system (e.g., 210a of FIG. 2B), the sudden loss of lubrication pressure 615 is an inflection point 625 that triggers an alarm. When the upper seal assembly (e.g., 300a of FIG. 2B) has reached a state such that the durable seal insert (e.g., 320 of FIG. 3A) is fully worn, the lower seal assembly (e.g., 300b of FIG. 2B) typically can maintain the pressure tight seal on drillpipe (e.g., 250 of FIG. 2B) for a limited amount of time. Thus, the alarm triggered by the inflection 625 is a warning to the rig personnel that they are on the clock because the upper seal assembly (e.g., 300a of FIG. 2B) has mere hours of operational life remaining because it now relies solely on its buffer material (e.g., 330 of FIG. 3A) to maintain the pressure tight seal. In this way, prior art methods analyzed patterns in the amount of closing pressure (e.g., 605, 610) required to activate a seal assembly (e.g., 300a or 300b), the lubrication pressure 615, and the wellbore pressure 620 to predict the end of design life of a sealing element a seal assembly (e.g., 300a or 300b) once the sealing element of at least one seal assembly is substantially or fully worn.

[0048] While there are a number of advantages to the co-molded construction of the durable seal insert (e.g., 320 of FIG. 3A) and the buffer material (e.g., 330 of FIG. 3A), the wear pattern from operative use varies when both materials are present (e.g., 300 of FIG. 5B) as opposed to when the durable seal insert (e.g., 320 of FIG. 3A) is worn away and only the buffer material (e.g., 330 of FIG. 3A) remains (e.g., 300 of FIG. 5D). In operation, when the closing pressures 605, 610 are maintained at a substantially constant value, the depletion of the wear-resistant durable seal insert (e.g., 320 of FIG. 3A) results in a sudden decrease in the lubrication pressure 615, causing an inflection point 625 in both the lubrication pressure 615 and shortly thereafter in the closing pressure for the upper annular packer (e.g., 210a of FIG. 2B), because the control system (e.g., 800 of FIG. 8 or 900 of FIG. 9) attempts to compensate for the loss of lubrication pressure 615. The inflection point 625 at which the durable seal insert (e.g., 320 of FIG. 3A) is depleted is clearly identifiable by the control system (e.g., 800 of FIG. 8 or 900 of FIG. 9) of the ACD annular sealing system (e.g., 200 of FIG. 2B). While information about this inflection point 625 has some value, it fails to comprehend the reality that the seal assembly (e.g., 300a or 300b of FIG. 2B) reaches the end of its design life well before actual failure of the seal. For example, using prior art methods, once the inflection point is reached, the drillstring (not shown) is stripped to a safe location so that the worn seal assembly (e.g., 300a or 300b of FIG. 2B) may be replaced, despite the fact that the seal assembly (e.g., 300a or 300b of FIG. 2B) has remaining life. As such, prior art methods have been successful in predicting the end of the design life of a seal assembly (e.g., 300a or 300b of FIG. 2B), which has improved the safety and efficiency of deepwater ASBP- MPD operations. However, in terms of actionable information, prior art methods merely signify the ability to continue operations or the need to replace the retrievable seal assembly (e.g., 300a or 300b of FIG. 2B), without more. Prior art methods, at best, provide early warning of imminent seal failure prior to damaging system components. And while the detectable inflection point 625 signifies the depletion of the durable seal insert (e.g., 320 of FIG. 2B), rig personnel have no information as to how much actual time remains before the sealing element formed by the durable seal insert (e.g., 320 of FIG. 2B) and the buffer material (e.g., 330 of FIG. 2B) fails. Worse still, the rig personnel have no ability to manage commands given to the system in real time in an effort to extend the operable life of seal assembly (e.g., 300a or 300b of FIG. 2B) to, for example, finish a section. This has the practical consequence of the rig personnel simply replacing seal assembly (e.g., 300a or 300b of FIG. 2B) upon detection of the inflection point 625. Importantly, the prior art methods provide no information regarding the real time consumption of the sealing element, the impact that present operations have on the real time consumption of the sealing element, or the ability to determine the operative life remaining for a sealing element over the entire life of the sealing element.

[0049] Accordingly, in one or more embodiments of the present invention, a method of predictive wear state modeling enables continuous monitoring of a wearable sealing element over its entire operative life. In one or more embodiments of the present invention, a near real-time consumption rate is determined that provides actionable information to rig personnel regarding the operative use of a sealing element, from initial deployment through retirement, not just an indication of an imminent seal failure. A control system may sample process control data at predetermined intervals including one or more of the closing pressures and lubrication pressure of the ACD annular sealing system, wellbore pressure, drillpipe rotation per minute (“RPM”), tool joint diameter, drillpipe diameter, and other information including whether the tool joint is in a seal sleeve or whether drillpipe is in-slips, to determine an effective value of energy dissipated by the sealing element for each unit of time. In certain embodiments, a raw estimate of the value of energy dissipated per unit time may be determined based on the normal force per unit area of sealing element acting on the drillstring and the total displacement of the drillstring during that time unit. In other embodiments, a value of energy dissipated per unit time may be determined by modifying the raw estimate for excess wear conditions, such as, for example, high drillstring RPM, excess closing pressure, and periods of little to no wear of the sealing element, where the sealing element is not in contact with the drillstring. Advantageously, it has been determined that calculated values of energy dissipation highly correlate with depletion of the durable seal insert such that cumulative energy dissipation over time correlates to depletion of the sealing element and corresponding weight reduction. In still other embodiments, offline analysis of prior data and multiple regression analysis may enable the results to be corrected for the position of sealing element (e.g., whether used as part of the upper or lower annular packer system, drilling fluid composition, and variation in post run weight of the sealing element.

[0050] During normal operations of the rig, process control data is typically recorded at predetermined intervals, typically every second. This process control data may include axial displacement of a component, angular displacement of a component, axial velocity of a component, angular velocity of a component, closing pressure applied to the upper annular packer of the ACD annular sealing system, closing pressure applied to the lower annular packer of the ACD annular sealing system, lubrication pressure of the lubrication chamber of the ACD annular sealing system, wellbore pressure, temperatures, flow rates, and cumulative values of the previous process data over a period of time. This process control data may be used to determine a state of the drilling system at any point in time. Given a set of rules or conditions, state detection may indicate whether a drillstring is supported by a set of slips or is supported by a travelling block system. State detection may indicate whether a first smaller diameter member is in contact with an active sealing element or whether a second larger diameter member is in contact with the active sealing element.

[0051] In one or more embodiments of the present invention, a normal force applied between a sealing element and a pipe member of drillstring may be approximated by a pressure acting on the sealing element and the contact area between the sealing element and the pipe member. A total displacement of a rotating and reciprocating body within a sealing element may be approximated by finding the length of the hypotenuse of a triangle where the adjacent side length is the radial displacement of a rotating and reciprocating body and the opposite side length is the axial displacement of the rotating and reciprocating body. Work performed by the rotating and reciprocating body against a sealing element may be approximated by multiplying an approximate normal force and an approximate total displacement within a time period. Work performed by a rotating and reciprocating body against a sealing element is the same as energy absorbed by a sealing element may be expressed in terms of ft-lbs, joules, or any other unit of energy. Cumulatively, work performed by a rotating and reciprocating body against a sealing element may be correlated to a cumulative weight loss of a sealing element during service. A terminal value representing a sealing element design life may be designated in terms of the weight of a sealing element at the end of its design life or in terms of the work or energy dissipated by a sealing element at the end of its design life. At any point in a sealing element’s life, cumulative energy absorbed in relation to a terminal value of energy absorbed may be used to approximate the consumed and remaining portions of the sealing element. Such an approximation may also be used to project an estimate for the safe operating time remaining given the current and past control parameters applied.

[0052] While the above is sufficient to approximate a raw value of energy absorption by an active sealing element, it may be advantageous to adjust an approximation for nonlinearities or discontinuities in the real-world performance of a sealing element. Some operating conditions may result in more rapid abrasion or erosion of a sealing element. Excessive application of pressure to an active sealing element may result in the generation of excess heat or cause excess abrasion or erosion of the element. Excessive angular speed of a drillstring may also cause excess heat or excess abrasion. Other operating conditions, such as when a sealing element is partially but not wholly activated, may result in little to no wear of a sealing element. To improve the accuracy of a predictive wear model, a raw process control value may be corrected for non-linear effects. Thresholds may also be implemented to prevent a predictive model from counting when a process variable is below a known threshold or when a process variable is above a known threshold. Several methods exist for defining mathematical correction factors or thresholds. These may be obtained through finite element analysis and other computational methods used generally in material science or through empirical methods that may include results from physical testing, trial of correction factors in combination with multiple regression analysis, and use of machine learning or other statistical methods. A model may be considered predictive once a terminal value of energy absorption is defined and a function is attained which minimizes residual error on a cumulative basis to a degree that is acceptable for the process or system at hand.

[0053] Once a terminal value of energy absorption is defined and a predictive model is satisfactorily attained, the two may be used in tandem to quantify wear in real time, score how a sealing element is being used in real time to provide feedback to the rig personnel or control system, and predict future wear based on historical data and predictive analysis. For any point in time, a control system may display as a percentage or a ratio of the approximate cumulative energy absorbed by a sealing element over a terminal value of safely absorbable energy for the sealing element, representing a sealing element’s consumed life. A control system may then calculate as a percentage or a ratio of the approximate cumulative energy absorbed by an element over a terminal value of safely absorbable energy, representing a sealing element’s remaining life. A control system may also calculate low and high estimates to indicate uncertainty in the approximate values of consumed or remaining life for a sealing element. Furthermore, any of the above approximate values of remaining seal life may be used in combination with current or past process control information to estimate the time remaining until a terminal value of seal life for a sealing element is reached.

[0054] In one or more embodiments of the present invention, a predictive wear state model may describe energy applied to a sealing element at a point in time as shown in Equation 1 that is then summed over a period of time to calculate a total energy applied to a sealing element for a predetermined time period as shown in Equation 6. This represents a raw estimate of the energy absorbed by a wearable sealing element, as discussed in more detail herein.

[0055] Energy [lb — ft] = Normal Force [lb] * Displacement [ft] (Eq. 1)

[0056] The normal force in Equation 1 may be calculated as the product of the applied pressure and contact area as shown in Equation 2.

[0058] The pressure in Equation 2 may be the applied pressure shown in Equation 3 that may be defined to include both the closing pressure required to hydraulically actuate the piston that drives the annular packer element into a sealing element and the effects of the process fluid on a sealing element. [0060] The area in Equation 2 may be the contact area shown in Equation 4. The contact area may be defined to include the outer diameter of a rotating body, such as, for example, drillpipe, rotating concentrically within a sealing element. State detection may be used to determine if the outer diameter used is a first smaller outer diameter or a second larger outer diameter.

[0061] Area [in ² ] = OD [in]) * n * (Contact Length [in]) (Eq. 4)

[0062] The displacement in Equation 1 may be defined as shown in Equation 5 to account for angular displacement as well as axial displacement of a rotating body, such as, for example, drillpipe, rotating concentrically within a sealing element. [0064] Equations 1 through 5 may be used to determine a raw estimate of applied energy to a sealing element for each record in a time series of data. Notwithstanding, other formulations of normal force, pressure, area, and displacement may be used to describe measured or implied values. For example, applied pressure may be conditionally set to zero if it is known that a sealing element is not in contact with the drillstring. A pressure dependent factor may also be applied to a raw pressure value to account for excess wear due to high pressure. Similarly, a rotation dependent factor may also be applied to a raw pressure value to account for excess wear due to high angular velocity. In Equation 6, the sum of applied energy applied to a sealing element for all records in the time series of data.

[0065] Total Energy = ^ ₌₁ Energy _t (Eq. 6)

[0066] At the end of a sealing element’ s life, the total energy applied to the sealing element may be associated with the weight reduction, or material depletion, of the sealing element due to wear. The above-described formulation, or derivatives thereof, may therefore be used to approximate an amount of energy absorbed by an element from process control data, that the rig may already collect and possess in the normal course of its operation. [0067] In one or more embodiments of the present invention, it was discovered that terminal values for end of life or end of design conditions may be used to enhance the predictive model. At the end of a sealing element’s life, it is likely to weigh less due to material loss from abrasion and erosion. Where feasible, terminal values for energy absorption may be determined through iterative testing under a set of operating conditions where a test is run until the end of design life of a sealing element has been reached. Process control data gathered during such a test may be input into a model as described in Equation 1 through Equation 6 to arrive at an approximation for the total energy absorbed by a sealing element. Depending on the cost of procuring one or more sealing element for test, the time to reach the end of design life condition, or the need to meet commercial obligations, it may not be feasible to determine a terminal value of energy absorbed by a sealing element through testing alone.

[0068] In one or more embodiments of the present invention, an alternative is to determine a terminal value of energy absorbed by a sealing element including feedback data from past operations. Usage data, such as process control data for the entire sealing element’s life, and some definitive data of a sealing element indicating the end of design life, such as its final weight at the end of design life. Environmental data, such as fluid compositions or location of a sealing element within a system may also be relevant. For each case, a value for the final weight may be plotted on the independent axis and a value for the total energy absorbed for that sealing element may be plotted on the dependent axis. Generally, the weight at the end of a sealing element’s life and raw approximations for absorbed energy will correlate, however it is likely that such a correlation includes a non-negligible amount of unexplained error, resulting in a wide range of possible values for absorbed energy at the end of the sealing element’s life. Reducing the error in the correlation may be achieved by recalculating the total energy absorbed for each record of each run introducing correction factors or correction functions and replotting the adjusted energy absorption data. For example, FIG. 7A shows an exemplary plot of raw values of absorbed energy by an actively controlled sealing element versus hours of seal usage in accordance with one or more embodiments of the present invention. FIG. 7B shows exemplary plot of adjusted values of absorbed energy by an actively controlled sealing element versus hours of seal usage in accordance with one or more embodiments of the present invention.

[0069] In one or more embodiments of the present invention, application of optimal correction factors may account for non-linear wear. Separating data based on the fluid composition or a location of use within the ACD annular sealing system may also reduce error. Solving for correction factors or functions may be achieved through trial and error or through the use of a solving program. When the error is satisfactorily minimized, adjusted data representing total energy absorbed over the life of a sealing element will align in a manner which is more linear compared to the raw energy absorbed values. Notably, having lost a predefined amount of weight, a sealing element at the end of its life will have an associated terminal value of cumulative adjusted energy absorbed. If the error minimization process fully eliminates error, then a single model may be used to predict the remaining sealing element life. More likely, the error minimization process results in a narrow band of potential values around a model of best fit. Thus, it may be advantageous to define multiple models to describe a high value for energy absorbed, a low value for energy absorbed, and a best fit value for energy absorbed. Critically, a model with minimal error serves as a proxy for cumulative sealing element wear so that a process control system may interpret aggregate adjusted energy absorbed at any point in time as seal material consumed at any point in time.

[0070] In one or more embodiments of the present invention, once the error of an energy absorption model is satisfactorily minimized, the model may be used as a predictive model in the control system. A function to calculate the adjusted energy absorbed by a sealing element using the live process control data for each time series record may be deployed in the control system. A separate function to sum the cumulative adjusted energy absorbed is likewise deployed to amass all values for adjusted energy absorbed since an element is first used. A third function may use the cumulative adjusted energy absorbed for a presently operated sealing element and a terminal value for cumulative adjusted energy absorbed to determine as a percentage or a ratio of the approximate energy absorbed over a terminal value of safely absorbable energy for the sealing element, representing a sealing element’s consumed life. In addition, we may calculate as a percentage one less than the ratio of the approximate cumulative energy absorbed by an element over a terminal value of safely absorbable energy, representing a sealing element’s remaining life.

[0071] In one or more embodiments of the present invention, once a terminal value of energy absorption is defined and a predictive model is satisfactorily attained, they may be used in tandem to quantify wear of a sealing element in real time and score how a sealing element is being used in real time, providing feedback to the human operator or control system, and providing a reliable indication of the remaining life of the sealing element. For any point in time, a control system may display as a percentage or a ratio of the approximate cumulative energy absorbed by a sealing element over a terminal value of safely absorbable energy for the sealing element, representing a sealing element’s consumed life. A control system may calculate as a percentage 1 less the ratio of the approximate cumulative energy absorbed by a sealing element over a terminal value of safely absorbable energy, representing a sealing element’s remaining life. A control system may also calculate low and high estimates to indicate uncertainty in the approximate values of consumed or remaining sealing element life. Furthermore, any of the above approximate values of remaining sealing element life may be used in combination with current or past process control information to estimate the time remaining until a terminal value of sealing element life is reached. Specifically, a control system may consider the time elapsed since a sealing element entered service or the time in active service and divide it by the ratio representing the consumed life to project forward a time until the end-of-life state is reached, however this may bias the projection based on past performance. Alternatively, a control system may input the current instantaneous or moving average process control parameters to an adjusted, best-fit predictive model to predict run time until the end-of-life condition is met. The elapsed time may then be subtracted from a predicted run time to determine the safe remaining useful life before the sealing element requires replacement. Similarly, a safe remaining useful life may be approximated for high and low case predictive models to provide a range of potential safe operating times remaining. Further, the best-fit, high, or low case predictive models may calculate, store, or display sealing element life consumed or remaining in terms of percentages, element weight, consumed weight, or visually through digital display, graphical plotting, or animations. Further still, a control system may also interpret results of a predictive model to alert human operators when a predicted remaining sealing element life reaches predetermined thresholds which may serve as decision gates to determine whether operations should continue or pause to replace an element.

[0072] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element includes applying an external energy source to actuate the sealing element to form an interference fit with a pipe member disposed through a lumen of the sealing element. In certain embodiments, a control system may apply the external energy source by applying hydraulic actuation fluid to a piston that displaces an annular packer element that travels within a radiused annular packer housing and causes at least a portion of the sealing element to flex so as to form an interference fit with the pipe member disposed therethrough.

[0073] One or more methods may further include actively controlling the application of the external energy source to maintain the sealing element’s interference fit with the pipe member. In certain embodiments, where the application of an external energy source is hydraulic actuation that creates closing pressure, more or less closing pressure may be required to maintain the interference fit. As the sealing element wears from use, the control system may provide additional closing pressure to maintain the interference fit.

[0074] One or more methods may further include collecting process control data at predetermined intervals. In certain embodiments, a control system may collect process control data at predetermined intervals and may optionally store the data locally. The process control data may include one or more of axial displacement of the pipe member, angular displacement of the pipe member, axial velocity of the pipe member, angular velocity of the pipe member, closing pressure of an upper annular packer system of an ACD annular sealing system, closing pressure of a lower annular packer system of the ACD annular sealing system, lubrication pressure of the lubrication chamber of the ACD annular sealing system, wellbore pressure, temperature, flow rate, and cumulative values thereof.

[0075] One or more methods may further include, for each predetermined interval, determining a raw energy value of energy absorbed by the sealing element based at least in part on the collected process control data. In certain embodiments, the control system may determine the raw value of energy absorbed by calculating a normal force corresponding to pressure applied to the sealing element and the contact area between the sealing element and the pipe member, calculating a displacement of the pipe member relative to the sealing element, and calculating the raw value of energy absorbed by the sealing element as a product of the normal force and the displacement.

[0076] One or more methods may further include adjusting the raw value of energy absorbed based on one or more known physical relationships, correction factors, logical functions, or statistical functions. One or more methods may further include calculating a raw value of total energy absorbed by the sealing element. In certain embodiments, the control system may calculate the raw value of total energy absorbed by summing the raw value of energy absorbed per predetermined period for a plurality of periods. The raw value of total energy absorbed may be adjusted with historical data, process control data, starting weight of the sealing element, and final weight of the sealing element. [0077] One or more methods may further include determining a terminal value for total energy absorbed by the sealing element. In certain embodiments, the control system may determine past values for total energy absorbed by similar sealing elements. One or more methods may further include predicting a terminal value for total energy absorbed by the sealing element based on historical data. One or more methods may further include predicting a remaining life for the sealing element based on the total energy absorbed by the sealing element and the predicted terminal value for total energy absorbed by the sealing element.

[0078] One or more methods may further include providing an indication of one or more of the raw value of energy being absorbed by the actively controlled sealing element, the total energy absorbed by the sealing element, a predicted terminal value for total energy absorbed by the sealing element, or a remaining life for the sealing element. In certain embodiments, the control system may provide the indication via a graphical display or audible. One or more methods may further include generating a predictive model that relates historical weight loss values of similar sealing elements to raw values for total energy absorbed by the sealing element.

[0079] FIG. 8 shows a control system 800 in accordance with one or more embodiments of the present invention. A control system 800 is a type of computing system that is sometimes used on drilling rigs to control various equipment and execute various methods. In one or more embodiments of the present invention, control system 800 may be used to execute any of the above-described methods. One of ordinary skill in the art will recognize that control system 800 disclosed herein is merely exemplary and other control systems that are well known in the art may be used in a similar manner in accordance with one or more embodiments of the present invention.

[0080] Control system 800 may include one or more central processing units, sometimes referred to as processors (hereinafter referred to in the singular as “CPU” or plural as “CPUs”) 805, host bridge 810, input/output (“IO”) bridge 815, graphics processing units (singular “GPU” or plural “GPUs”) 820, and/or application-specific integrated circuits (singular “ASIC or plural “ASICs”) (not shown) disposed on one or more printed circuit boards (not shown) that perform computational operations. Each of the one or more CPUs 805, GPUs 820, or ASICs (not shown) may be a single-core (not independently illustrated) device or a multi-core (not independently illustrated) device. Multi-core devices typically include a plurality of cores (not shown) disposed on the same physical die (not shown) or a plurality of cores (not shown) disposed on multiple die (not shown) that are collectively disposed within the same mechanical package (not shown).

[0081] CPU 805 may be a general -purpose computational device typically configured to execute software instructions. CPU 805 may include an interface 808 to host bridge 810, an interface to system memory 820, and an interface 823 to one or more IO devices, such as, for example, one or more GPUs 825. GPU 825 may serve as a specialized computational device typically configured to perform graphics functions related to frame buffer manipulation. However, one of ordinary skill in the art will recognize that GPU 825 may be used to perform non-graphics related functions that are computationally intensive. In certain embodiments, GPU 825 may interface 823 directly with CPU 805 (and interface 818 with system memory 820 through CPU 805). In other embodiments, GPU 825 may interface 821 with host bridge 810 (and interface 816 or 818 with system memory 820 through host bridge 810 or CPU 805 depending on the application or design). In still other embodiments, GPU 825 may interface 833 with IO bridge 815 (and interface 816 or 818 with system memory 820 through host bridge 810 or CPU 805 depending on the application or design). The functionality of GPU 825 may be integrated, in whole or in part, with CPU 805.

[0082] Host bridge 810 may be an interface device that interfaces between the one or more computational devices and IO bridge 815 and, in some embodiments, system memory 820. Host bridge 810 may include an interface 808 to CPU 805, an interface 813 to IO bridge 815, for embodiments where CPU 805 does not include an interface 818 to system memory 820, an interface 816 to system memory 820, and for embodiments where CPU 805 does not include an integrated GPU 825 or an interface 823 to GPU 825, an interface 821 to GPU 825. The functionality of host bridge 810 may be integrated, in whole or in part, with CPU 805. IO bridge 815 may be an interface device that interfaces between the one or more computational devices and various IO devices (e.g., 840, 845) and IO expansion, or add-on, devices (not independently illustrated). IO bridge 815 may include an interface 813 to host bridge 810, one or more interfaces 833 to one or more IO expansion devices 835, an interface 838 to keyboard 840, an interface 843 to mouse 845, an interface 848 to one or more local storage devices 850, and an interface 853 to one or more network interface devices 855. The functionality of IO bridge 815 may be integrated, in whole or in part, with CPU 805 and/or host bridge 810. Each local storage device 850, if any, may be a solid-state memory device, a solid-state memory device array, a hard disk drive, a hard disk drive array, or any other non-transitory computer readable medium. Network interface device 855 may provide one or more network interfaces including any network protocol suitable to facilitate networked communications.

[0083] Control system 800 may include one or more network-attached storage devices 860 in addition to, or instead of, one or more local storage devices 850. Each network-attached storage device 860, if any, may be a solid-state memory device, a solid-state memory device array, a hard disk drive, a hard disk drive array, or any other non-transitory computer readable medium. Network-attached storage device 860 may or may not be collocated with control system 800 and may be accessible to control system 800 via one or more network interfaces provided by one or more network interface devices 855.

[0084] One of ordinary skill in the art will recognize that control system 800 may be a conventional computing system, an industrial computing system (not shown), or an application-specific computing system (not shown). In certain embodiments, an industrial computing system (not shown) or an application-specific computing system (not shown) may include one or more ASICs (not shown) that perform one or more specialized functions in a more efficient manner. The one or more ASICs (not shown) may interface directly with CPU 805, host bridge 810, or GPU 825 or interface through IO bridge 815. Alternatively, in other embodiments, an industrial computing system (not shown) or an application-specific computing system (not shown) may be reduced to only those components necessary to perform a desired function in an effort to reduce one or more of chip count, printed circuit board footprint, thermal design power, and power consumption. The one or more ASICs (not shown) may be used instead of one or more of CPU 805, host bridge 810, IO bridge 815, or GPU 825. In such systems, the one or more ASICs may incorporate sufficient functionality to perform certain network and computational functions in a minimal footprint with substantially fewer component devices.

[0085] As such, one of ordinary skill in the art will recognize that CPU 805, host bridge 810, IO bridge 815, GPU 825, or ASIC (not shown) or a subset, superset, or combination of functions or features thereof, may be integrated, distributed, or excluded, in whole or in part, based on an application, design, or form factor in accordance with one or more embodiments of the present invention. Thus, the description of control system 800 is merely exemplary and not intended to limit the type, kind, or configuration of component devices that constitute a control system 800 suitable for executing methods in accordance with one or more embodiments of the present invention. Notwithstanding the above, one of ordinary skill in the art will recognize that control system 800 may be a standalone, laptop, desktop, industrial, server, blade, or rack mountable system and may vary based on an application or design.

[0086] FIG. 9 shows a programmable logic device (“PLD”) system 900 in accordance with one or more embodiments of the present invention. A PLD system 900 is a type of industrial computing system or application-specific computing system that is sometimes used on drilling rigs to control various equipment and execute various methods. In one or more embodiments of the present invention, PLD system 900 may be used in addition to, or in place of, control system 800, to execute any of the above-described methods. One of ordinary skill in the art will recognize that PLD system 900 disclosed herein is merely exemplary of a PLD system and other PLD systems that are well known in the art may be used in a similar manner in accordance with one or more embodiments of the present invention.

[0087] The primary component of a PLD system 900 is a PLD 905 such as, for example, a programmable array logic (“PAL”), a field-programmable gate array (“FPGA”), or a complex programmable logic device (“CPLD”). PLD 905 is distinguished from a conventional CPU (e.g., 805 of FIG. 8) in that it is an undefined logic device that has no predetermined logical function until programmed by a user. In many PLD systems 900, the user’s programming is stored in a programming device 910 that programs the PLD 905 upon boot up to implement the user’ s desired function. PLD system 900 also includes system memory 915, storage 917, power supply 920, an input interface 925, and an output interface 930. The input interface 925 includes one or more inputs that may receive data from one or more downhole sensors, surface-based sensors, rig sensors, or other sources of relevant process control data. The output interface 930 includes one or outputs that may be used to control various equipment. The description of PLD system 900 is merely exemplary and not intended to limit the type, kind, or configuration of component devices that constitute a PLD system 900 suitable for executing methods in accordance with one or more embodiments of the present invention.

[0088] 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 abovenoted methods in accordance with one or more embodiments of the present invention.

[0089] Advantages of one or more embodiments of the present invention may include one or more of the following: [0090] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element enables continuous monitoring of a wearable sealing element over its entire operative life from initial deployment through to retirement, not just an indication of imminent seal failure.

[0091] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element provides a near real-time consumption rate of a wearable sealing element that allows rig personnel to modify the actions they take relative to the consumption rate of the wearable sealing element.

[0092] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element determines an amount of energy dissipated by the actively controlled sealing element.

[0093] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element the amount of energy dissipated by the actively controlled sealing element may be correlated with the depletion of the durable seal insert and corresponding reduction in weight of the actively controlled sealing element.

[0094] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element provides an indication as to how much operative life remains for the actively controlled sealing element.

[0095] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element uses data already captured by existing instrumentation commonly found on a drilling rig.

[0096] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element enables live operation where a predictive model may be used to compare performance during a current run to a predictive model.

[0097] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element may use cumulative values of past performance to create an adjusted predictive model that indicate the amount of operative life of the sealing element already consumed or the remaining life of the sealing element.

[0098] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element reduces no-productive down time and maximizes return on investment for each and every actively controlled sealing element.

[0099] In one or more embodiments of the present invention, a method of predictive wear state modeling for an actively controlled sealing element may be used with any type or kind of actively controlled sealing element.

[0100] 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.