Patent Publication Number: US-10781657-B2

Title: Intelligent RCD system

Description:
BACKGROUND 
     During downhole drilling operations, an earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. When weight is applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. Because of the energy and friction involved in drilling a wellbore in the earth&#39;s formation, drilling fluids, commonly referred to as drilling mud, are used to lubricate and cool the drill bit as it cuts the rock formations below. Furthermore, in addition to cooling and lubricating the drill bit, drilling mud also performs the secondary and tertiary functions of removing the drill cuttings from the bottom of the wellbore and applying a hydrostatic column of pressure to the drilled wellbore. 
     Typically, drilling mud is delivered to the drill bit from the surface under high pressure through a central bore of the drillstring. From there, nozzles on the drill bit direct the pressurized mud to the cutters on the drill bit where the pressurized mud cleans and cools the bit. As the fluid is delivered downhole through the central bore of the drillstring, the fluid returns to the surface in an annulus formed between the outside of the drillstring and the inner profile or wall of the drilled wellbore. Drilling mud returning to the surface through the annulus does so at lower pressures and velocities than it is delivered. Nonetheless, a hydrostatic column of drilling mud typically extends from the bottom of the hole up to a bell nipple of a diverter assembly on the drilling rig. Annular fluids exit the bell nipple where solids are removed, the mud is processed, and then prepared to be re-delivered to the subterranean wellbore through the drillstring. 
     As wellbores are drilled several thousand feet below the surface, the hydrostatic column of drilling mud in the annulus serves to help prevent blowout of the wellbore, as well. Often, hydrocarbons and other fluids trapped in subterranean formations exist under significant pressures. Absent any flow control schemes, fluids from such ruptured formations may blow out of the wellbore and spew hydrocarbons and other undesirable fluids (e.g., H 2 S gas). 
     Thus, rotating control devices (“RCD”) are frequently used in oilfield drilling operations where elevated annular pressures are present to seal around drill string components and prevent fluids in the wellbore from escaping. For example, conventional RCDs may be capable of isolating pressures in excess of 1,000 psi while rotating (i.e., dynamic) and 2,000 psi when not rotating (i.e., static). However, conventional RCDs may be designed to isolate other ranges of pressures, depending on the formations being drilled and type of drilling operations being conducted. A RCD may include a packing or sealing element and a bearing package, whereby the bearing package allows the sealing element to rotate along with the drillstring. Therefore, in using a RCD, there is no relative rotational movement between the sealing element and the drillstring, only the bearing package exhibits relative rotational movement. Examples of RCDs include U.S. Pat. Nos. 5,022,472 and 6,354,385. In some instances, dual stripper rotating control devices having two sealing elements, one of which is a primary seal and the other a backup seal, may be used. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         FIG. 1  is a cross-sectional diagram of an RCD assembly according to embodiments of the present disclosure. 
         FIG. 2  is a cross-sectional drawing of an RCD assembly according to embodiments of the present disclosure. 
         FIG. 3  is a cross-sectional drawing of a bearing package of the RCD assembly of  FIG. 2 . 
         FIG. 4  is a cross-sectional drawing of a sealing component of the RCD assembly of  FIG. 2 . 
         FIG. 5  shows a system according to embodiments of the present disclosure. 
         FIG. 6  shows a system in accordance with embodiments of the present disclosure. 
         FIG. 7  shows a method according to embodiments of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     Downhole drilling operations, including managed pressure drilling (MPD) and under balanced drilling operations through subsurface formations may include the use of an assembly known as a rotating control head or rotating control device (RCD). A rotating flow head is an apparatus for well operations which diverts fluids such as drilling mud, surface injected air or gas and other produced wellbore fluids, into a recirculating or pressure recovery “mud” (drilling fluid) system. The RCD includes a bearing package and seal assembly that enables rotation of a drill string and longitudinal motion of a drill string as the wellbore is drilled, while maintaining a fluid-tight seal between the drill string and the wellbore so that drilling fluid discharged from the wellbore may be discharged in a controlled manner. By controlling discharge of the fluid from the wellbore, a selected fluid pressure may be maintained in the annular space between the drill string and an exterior of the wellbore. Control of the discharge may be performed manually or automatically, such as by using a choke to restrictively allow fluid flow through a return flow line. 
       FIG. 1  shows a diagram of an example of an RCD assembly  10  according to embodiments of the present disclosure. The RCD assembly  10  is disposed around a drill string  50  and includes a bearing package  20 , at least one sealing component  30 , latching components  40 , and an RCD housing  12 . The sealing components  30  may be referred to as sealing elements or packers. As shown, in some embodiments, there may be an upper sealing element  30  and a lower sealing element  30  disposed around the drill string  50 . A bearing outer seal  22  may be disposed between the bearing package  20  and the RCD housing  12 . The latching components  40  may include landing pistons  42  and latching pistons  44 . However, other types of latching components may be used to hold an RCD assembly in place within a wellbore casing or riser (not shown). The sealing elements  30  grip around the drill string  50  such that the RCD assembly  10  rotates with the drill string  50 . Drill string slip (when the drill string rotates at a different rate than the RCD assembly) may indicate wear or failure of one or more components in the RCD assembly, e.g., fatigue of a sealing element or contaminants in the bearing package. 
     A plurality of sensors may be disposed along the RCD assembly  10  to monitor performance of various components within the RCD assembly  10 . Sensor types may include, for example, frequency sensors, temperature sensors, position sensors, pressure sensors, and vibration sensors. For example, as shown, one or more types of pressure sensors  11  may be disposed on the RCD housing  12  above and below the bearing package  20  and disposed within the bearing package  20  between the upper and lower sealing elements  30 . The pressure sensors may be used to monitor the pressure of the areas in which they are disposed, which may be used, for example, to analyze and/or predict the condition of the components of the RCD assembly  10 . For example, a pressure sensor located on the RCD housing above the bearing package  20  may be used to measure hydraulic pressure in the well, and a pressure sensor located on the RCD housing below the bearing package  20  may be used to measure annular pressure of the well. In some embodiments, pressure sensors may be disposed within an RCD assembly and within the wellbore, where the pressure within the RCD assembly may be compared to the pressure in the wellbore. Relative pressure changes between the RCD assembly and the wellbore may indicate, for example, wear or failure of one or more components of the RCD assembly. 
     Pressure sensor types may include various types of devices known in the art that generate a signal as a function of the pressure imposed on the device. For example, pressure sensors types may include, but are not limited to capacitive pressure sensors, electromagnetic pressure sensors, piezoelectrics, optical pressure sensors, and potentiometric sensors. Other types of pressure sensors may include pressure indication assemblies having one or more pressure relief valves, one or more pistons, and one or more associated proximity switches, each piston assembled radially between a pressure relief valve and a proximity switch, where upon reaching a pressure greater than a preset pressure value of the pressure relief valve, the pressure relief valve opens and pushes the piston toward the proximity switch. The proximity switch may then send a signal indicating the proximity of the piston, which indicates a pressure greater than the preset pressure value of the pressure relief valve. 
     The bearing package  20  may include one or more internal pressure sensors  11  and temperature sensors  21 . Suitable temperature sensor types may include but are not limited to thermistors, thermocouples, bimetal sensors, infrared thermometers, and other thermometer types known in the art. Further, temperature sensors may be disposed on other components of the RCD assembly  10 . For example, temperature sensor  15  may be disposed on the RCD housing  10  below the bearing package  20  to measure the wellbore temperature. In some embodiments, temperature sensors may be disposed within an RCD assembly and within a wellbore to monitor relative changes in temperature between the fluid temperature in the wellbore and the fluid temperature within the RCD assembly. Changes in the temperature difference between the temperature measured in an RCD assembly and in the wellbore may indicate, for example, wear or failure of one or more components in the RCD assembly. 
     A seal wear detection sensor  31  may be disposed on the sealing components  30  for monitoring wear of the sealing components  30 . For example, seal wear detection sensor types may include but are not limited to Eddy-current sensors or ultrasonic sensors for detecting changes in material properties of the seals, which may indicate wear of the seal. 
     Frequency sensors  13  may be disposed on the bearing package  20 , for example on the bearing package outer housing, to measure the rotational speed of the bearing package and/or rotational speed of the drill string  50 . Suitable frequency sensors may include but are not limited to optical sensors, magnetic sensors, and other sensor types known in the art that are capable of measuring rotational speed. In embodiments monitoring the rotational speed of the bearing package  20  and the drill string  50 , the rotational speeds may be compared to determine if there is a mismatch in rotational speed, which may indicate slip. In some embodiments, one or more frequency sensors  13  may be used to monitor the rotational speed of the bearing package  20  and/or sealing component  30 , which may be compared with the inputted rotational speed of the drill string (e.g., the rotational speed of the drill string set by the operator at the platform or rig) to determine if there is a mismatch in rotational speed. 
     Vibration sensors  17  may be disposed on the RCD housing  12  to monitor the movement of the RCD assembly  10 . For example, when an RCD assembly is assembled along a riser (not shown), movement of the riser from drilling operations and heaves from the surrounding body of water may result in forces applied to the RCD assembly, which may fatigue different components of the RCD assembly. In some embodiments, one or more vibration sensors may be disposed on a bearing package of an RCD assembly, where the vibration sensors may detect vibrations in the bearing package. Suitable vibration sensors may include but are not limited to piezoelectric sensors, accelerometers, and other sensor types known to be capable of detecting vibration. 
     Further, in some embodiments, an RCD assembly  10  may include at least one position sensor  19  disposed on or near a latching component to monitor the position of the latching component. In some embodiments, at least one position sensor  19  may be disposed on a bearing package in a location that engages or is proximate to a latching component when it is in the latched position. Position sensors  19  may include but are not limited to magnetic sensors, capacitive transducers, Eddy-current sensors, piezoelectric transducers, inductive sensors, Hall effect sensors, and other sensors known in the art capable of measuring an absolute position or a relative position (such as by using displacement sensors). 
     Referring now to  FIGS. 2-4 , a more detailed example of an RCD assembly is provided.  FIG. 2  shows an RCD assembly  200  in an assembled state. The RCD  200  is composed of a housing  202 , a bearing package  204 , and a sealing component  206 . The housing  202  includes a lower connection  208  and an upper connection  210 , for example flange connections, to the remainder of a riser assembly (e.g., a slip joint), an inner bore  212 , and a pair of outlet flanges  214 ,  216 . One or more compartments or recesses  203  may be formed along the wall of the inner bore  212 , which may hold one or more sensors (not shown). For example, recesses  203  may have temperature sensors or pressure sensors disposed therein for monitoring the temperature and/or pressure of the medium within the inner bore  212 . In some embodiments, sensors may be disposed along the wall of the inner bore  212 . Further, one or more compartments or recesses  205  may be formed along the outer wall of the housing  202 , which may hold one or more sensors. For example, recesses  205  may have vibration sensors disposed therein for monitoring the amount of vibration the RCD assembly is being subjected to during operation. In some embodiments, sensors may be disposed on the outer wall of the housing  202  (as opposed to being disposed within a recess formed in the outer wall). In some embodiments, sensors may be positioned along two or more points on the RCD housing  202  to measure pitch and roll of the RCD assembly  200 . Suitable pitch and roll sensors may include, for example, pitch and roll sensors utilizing micro electro-mechanical systems, such as Microtilt sensors, attitude sensors, or other pitch and roll sensors utilizing accelerometers oriented in the x, y, and z orientations. 
     Outlet flanges  214 ,  216  may be used to connect the RCD assembly  200  to one or more fluid diverting conduits, but one of ordinary skill in the art will understand that the outlet flanges  214 ,  216  are not necessary to the functionality of the RCD assembly  200 . Particularly, outlet flanges  214 ,  216  may be relocated to other components of the riser assembly if desired. Furthermore, flange connections  208  and  210  may be of any particular type and configuration, but should be selected such that the RCD assembly  200  may sealingly mate with adjacent components of the riser assembly. 
     Referring now to  FIGS. 2 and 3  together, bearing package  204  is engaged within bore  212  of RCD  200 . As shown, bearing package  204  includes an outer housing  220 , a first locking assembly  222  to hold bearing package  204  within housing  202  of RCD  200 , and a second locking assembly  224  to hold the sealing component  206  within the bearing package  204 . Furthermore, bearing package  204  includes a bearing assembly  226  to allow an inner sleeve  228  to rotate with respect to outer housing  220  and a seal  230  to isolate bearing assembly  226  from wellbore fluids. A plurality of seals  232  are positioned about the periphery of outer housing  220  so that bearing package  204  may sealingly engage inner bore  212  of housing  202 . While seals  232  are shown to be O-ring seals about the outer periphery of bearing package  204 , one of ordinary skill in the art will appreciate than any type of seal may be used. One or more compartments or recesses  223  may be formed within the inner sleeve  228  to hold one or more sensors. For example, a frequency sensor, temperature sensor and/or pressure sensor may each be disposed within a recess  223  to measure and monitor selected conditions within the bearing package  204 . In some embodiments, one or more sensors (not shown) may be disposed on the inner surface of the inner sleeve  228  (as opposed to within a recess formed in the inner surface). Further, one or more recesses  225  may be formed within the outer wall of the outer housing  220  to hold one or more sensors. For example, a pressure sensor (not shown) may be disposed within a recess  225  to monitor the pressure between the bearing package  204  and the housing  202  of the RCD assembly  200 , which may indicate whether any failure in the seals  232  have occurred. In some embodiments, vibration sensors (not shown) may be disposed in recesses  223  formed in the inner sleeve  228  and/or in recesses  225  formed in the outer housing  220  to measure vibration of the bearing package  204 . 
     The first locking assembly  222  may be hydraulically actuated such that a plurality of locking lugs  234  are moved radially outward and into engagement with a corresponding groove within inner bore  212  of housing  202 . As shown in the assembled state in  FIG. 2 , two hydraulic ports, a clamp port  236  and an unclamp port  238 , act through housing  202  to selectively engage and disengage locking lugs  234  into and from the groove of inner bore  212 . One of ordinary skill in the art will understand that any clamping mechanism may be used to retain bearing package  204  within housing  202  without departing from the scope of the claimed subject matter. Particularly, various mechanisms including, but not limited to, electromechanical, hydraulic, pneumatic, and electromagnetic mechanisms may be used for first and second locking assemblies  222 ,  224 . Furthermore, as should be understood by one of ordinary skill in the art, bearing assembly  226  may be of any type of bearing assembly capable of supporting rotational and thrust loads. As shown in  FIGS. 2 and 3 , bearing assembly  226  is a roller bearing comprising two sets of tapered rollers. Alternatively, ball bearings, journal bearings, tilt-pad bearings, and/or diamond bearings may be used with bearing package  204  without departing from the scope of the claimed subject matter. 
     Referring now to  FIGS. 2, 3 and 4  together, sealing component  206  is engaged within bearing package  204 . As shown, the sealing component  206  includes a stripper rubber  240  and a housing  242 . While a single stripper rubber  240  is shown, one of ordinary skill would understand that more than one stripper rubber  240  may be used. Housing  242  may be made of high-strength steel and include a locking profile  244  at its distal end that is configured to receive a plurality of locking lugs  246  from second locking assembly  224  of bearing package  204 . Second locking assembly  224  retains packing element  206  within bearing package  204  (which, in turn, is locked within housing  202  by first locking assembly  222 ) when pressure is applied to a second hydraulic clamping port  248 . Similarly, when packing element  206  is to be retrieved from bearing assembly  204 , pressure may be applied to second hydraulic unclamping port  250  to release locking lugs  246  from locking profile  244 . Further, hydraulic lubricant may flow through ports  264 ,  266  and  268  to communicate with and lubricate bearing assembly  226 . 
     Referring now to  FIG. 4 , the stripper rubber  240  is constructed so that threaded tool joints of a drill string (not shown) may be passed therethrough. As such, stripper rubber  240  includes a through bore  254  that is selected to sealingly engage the size of drill pipe (not shown) that is to be engaged through RCD assembly  200 . Further, to accommodate the passage of larger diameter tool joints therethrough during a drill string tripping operation, stripper rubber  240  may include tapered portions  256  and  258 . Furthermore, stripper rubber  240  may include upset portions  260  on its outer periphery to effectively seal stripper rubber  240  with inner sleeve  228  of bearing package  204 , such that high pressure fluids may not bypass packing element  206 . 
     As assembled, stripper rubber  240  seals around the drill string and prevents high-pressure fluids from passing between sealing component  206  and bearing package  204 . Seal  230  of the bearing package  204  prevents high-pressure fluids from invading and passing through bearing assembly  226 , and seals  232  prevent high-pressure fluids from passing between housing  202  and bearing package  204 . Therefore, when packing element  206  is installed within bearing package  204  which is, in turn, installed within housing  202 , a drill string may engage through RCD  200  along a central axis  262  such that high-pressure annular fluids between the outer profile of the drill string and the inner bore of riser string are isolated from upper riser assembly components. One or more pressure sensors (not shown) may be disposed along the bearing package  204 , for example on the outer housing  220  or proximate the bearing assembly  226 , to monitor increases in pressure, which may indicate that one or more of the seals  230 ,  232  have failed. 
     According to some embodiments, a proximity sensor may be positioned in a bearing package  204 , for example, in a sensor pocket formed in a wall of the bearing package similar to the recesses  223 ,  225  shown in  FIG. 3 , to measure the position of a compensating piston, which may indicate the level of lubricant (e.g., oil) in an accumulator. For example, one or more accumulators may be disposed in an outer housing of a bearing package, each accumulator having an accumulator piston and spring disposed therein and a lubricant supplied through an accumulator lubricant port to the bearing package. The springs may supply the force to keep the bearing pressure above the wellbore pressure, and the pistons may move therein as temperature changes affect the lubricant volume. A proximity sensor may be positioned to detect the position of each piston, thereby indicating the volume of lubricant in the accumulator. For example, as a piston moves vertically lower in an accumulator, the piston could contact or be detected by a switch to indicate that the lubricant level was low. A suitable proximity sensor may include, for example, a limit switch, Hall Effect device or linear potentiometer. 
     In some embodiments, a bearing package may include a contamination sensor, which may be positioned in a sensor pocket formed in a wall of the bearing package, such as in a recess similar to recesses  223 ,  225  shown in  FIG. 3 . A contamination sensor may be used to indicate contamination in the lubrication system of a bearing package. Suitable contamination sensors may include, for example, a switch or other indicator of fluid resistivity. For example, a contamination sensor may measure a base resistivity of lubricant in a bearing package, a relatively higher resistivity measurement may indicate purer lubricant (e.g., when new lubricant is supplied), and a relatively lower resistivity measurement may indicate water and/or other contamination in the lubricant. 
     Sensors as described herein may be in wireless communication with or may be wired to a programmable logic controller, depending on, for example, the types of sensors being used, the location of the sensor on the RCD assembly, and the location of the RCD assembly, where the programmable logic controller may receive signals from the sensors and mediate data transmission to a computational device. The programmable logic controller may continuously monitor the state of the sensors and transmit data to the computational device. For example, a programmable logic controller may provide real-time feedback of pressure, temperature, frequency, position and/or other measurements provided from the sensor signals. 
     According to embodiments of the present disclosure, a drilling system may include a rotating control device assembly disposed around a drill string, a plurality of sensors disposed along the rotating control device assembly, a programmable logic controller in communication with the plurality of sensors, a computational device having a modeling software, and a data store storing measurement data processed by the programmable logic controller from signals received from the plurality of sensors, where the data store is in communication with the computational device. Drilling systems of the present disclosure utilizing an RCD may include onshore or offshore drilling systems. For example,  FIG. 5  shows an example of an offshore drilling system, and  FIG. 6  shows an example of an onshore drilling system. 
     Referring to  FIG. 5 , a drilling system according to embodiments of the present disclosure is shown. The drilling system includes an offshore drilling platform  100  having a rig floor  102  and a lower bay  104 . While offshore drilling platform  100  is depicted as a semi-submersible drilling platform, one of ordinary skill will appreciate that a platform of any type may be used including, but not limited to, drillships, spar platforms, tension leg platforms, and jack-up platforms. A riser assembly  106  extends from a subsea wellhead (not shown) to offshore drilling platform  100  and includes various drilling and pressure control components. 
     From top to bottom, riser assembly  106  includes a diverter assembly  108  (shown including a standpipe and a bell nipple), a slip joint  110 , a RCD  112 , an annular blowout preventer  114 , a riser hanger and swivel assembly  116 , and a string of riser pipe  118  extending to subsea wellhead (not shown). While one configuration of riser assembly  106  is shown and described in  FIG. 5 , one of ordinary skill in the art should understand that various types and configurations of riser assembly  106  may be used in conjunction with embodiments of the present disclosure. Specifically, it should be understood that a particular configuration of riser assembly  106  used will depend on the configuration of the subsea wellhead below, the type of offshore drilling platform  100  used, and the location of the well site. 
     Offshore drilling platform  100  may have significant relative axial movement (i.e., heave) between its structure (e.g., rig floor  102  and/or lower bay  104 ) and the sea floor. Therefore, a heave compensation mechanism (not shown) may be employed so that tension may be maintained in riser assembly  106  without breaking or overstressing sections of riser pipe  118 . As such, slip joint  110  may be constructed to allow 30 ft., 40 ft., or more stroke (i.e., relative displacement) to compensate for wave action experienced by drilling platform  100 . Furthermore, a hydraulic member  120  is shown connected between rig floor  102  and hanger and swivel assembly  116  to provide upward tensile force to a string of riser pipe  118  as well as to limit a maximum stroke of slip joint  110 . To counteract translational movement (in addition to heave) of drilling platform  100 , an arrangement of mooring line (not shown) may be used to retain drilling platform  100  in a substantially constant longitudinal and latitudinal area. 
     As shown, slip joint  110  is constructed as a three-piece slip joint having a lower section  122 , an upper section  124 , and a seal housing  126 . In operation, upper section  124  plunges into lower section  122  similar to a piston into a bore while seal housing  126  maintains a fluid seal between two sections  122 ,  124 . Thus, riser assembly  106  may be constructed such that diverter assembly  108  may be rigidly affixed relative to rig floor  100  and with riser string  118  rigidly affixed to the subsea wellhead below. Therefore, the heave and movement of drilling platform  100  relative to the subsea wellhead may be taken up by slip joint  110  and hydraulic member  120 . 
     In certain operations including, but not limited to MPD operations, riser assembly  106  may be required to handle high annular pressures. However, components such as diverter assembly  108  and slip joint  110  may not be constructed to handle the elevated annular fluid pressures associated with managed pressure drilling. In such embodiments, components in an upper portion of riser assembly  106  may be isolated from the elevated annular pressures experienced by components located in a lower portion of riser assembly  106 . For example, as shown, RCD  112  may be included in riser assembly  106  between riser string  118  and slip joint  110  to rotatably seal about a drillstring (not shown) and prevent high pressure annular fluids in riser string  118  from reaching slip joint  110 , diverter assembly  108 , and the environment. 
     The RCD  112  may be capable of isolating pressures in excess of 1,000 psi while rotating (i.e., dynamic) and 2,000 psi when not rotating (i.e., static) from upper portions of riser assembly  106 . While annular blowout preventer  114  may be capable of similarly isolating annular pressure, such annular blowout preventers are not intended to be used when the drill string is rotating, as would occur during an MPD operation. 
     A plurality of sensors, such as described in  FIGS. 1-4 , is disposed along one or more components of the RCD  112  and is in communication with a programmable logic controller  130 . The sensors may send signals wirelessly to the programmable logic controller  130  (e.g., by sending signals to a receiver within the programmable logic controller) or may be wired to the programmable logic controller  130 . The programmable logic controller  130  may process the signals received from the sensors and provide measurement data to a computational device  140  having modeling software thereon. Using the measurement data, modeling software on the computational device may model, monitor, and/or analyze performance of one or more components of the RCD  112 . 
     Computational devices may include one or more computer processor(s), associated memory (e.g., random access memory (RAM), cache memory, flash memory, etc.), one or more storage device(s) (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory stick, etc.), and numerous other elements and functionalities. The computer processor(s) may be an integrated circuit for processing instructions. A computational device may also include one or more input device(s), such as a touchscreen, keyboard, mouse, microphone, touchpad, electronic pen, or any other type of input device. Further, a computational device may include one or more output device(s), such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, projector, or other display device), a printer, external storage, or any other output device, where one or more of the output device(s) may be the same or different from the input device(s). Computational devices may be connected to a network (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, mobile network, or any other type of network) via a network interface connection. The input and output device(s) may be locally or remotely connected to the computer processor(s), memory, and storage device(s). Further, one or more elements of a computational device may be located at a remote location and connected to the other elements over a network. Many different types of computational devices exist, and the aforementioned input and output device(s) may take other forms. 
     Software instructions in the form of computer readable program code to perform embodiments of the technology may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium. Specifically, the software instructions may correspond to computer readable program code that when executed by a processor(s), is configured to perform embodiments of the technology. 
     Referring still to  FIG. 5 , the system may further include a downhole information system  150  in communication with the computational device  140 , where the downhole information system  150  may provide information about the drilling operation to the computational device. For example, the downhole information system  150  may include a plurality of measurement devices disposed along a downhole drilling assembly and a processor in communication with the plurality of measurement devices, where the measurement devices send signals to and are processed by the processor to provide measurement data for the downhole drilling assembly. In some embodiments, measurement data may include drilling operating parameters, such as speed of the drill string and pumping rate of fluid being pumped downhole, wellbore parameters, and bottom hole assembly (BHA) parameters. Various parameters of a drilling operation that may be collected and/or analyzed by a downhole information system are discussed below. 
     “Drilling performance” may be measured by one or more drilling performance parameters. Examples of drilling performance parameters include rate of penetration (ROP), rotary torque to turn the drilling tool assembly, rotary speed at which the drilling tool assembly is turned, drilling tool assembly lateral, axial, or torsional vibrations and accelerations induced during drilling, WOB, weight on reamer (WOR), forces acting on components of the drilling tool assembly, and forces acting on the drill bit and components of the drill bit (e.g., on blades and/or cutting elements). Drilling performance parameters may also include the torque along the drilling tool assembly, bending moment, alternative stress, percentage of fatigue life consumed, pump pressure, stick slip, dog leg severity, borehole diameter, deformation, work rate, azimuth and inclination of the well, build up rate, walk rate, and bit geometry. One skilled in the art will appreciate that other drilling performance parameters exist and may be considered without departing from the scope of the disclosure. 
     “Wellbore parameters” may include one or more of the following: the geometry of a wellbore and formation material properties (i.e. geologic characteristics). The trajectory of a wellbore in which the drilling tool assembly is to be confined also is defined along with an initial wellbore bottom surface geometry. Because the wellbore trajectory may be straight, curved, or a combination of straight and curved sections, wellbore trajectories, in general, may be defined by defining parameters for each segment of the trajectory. For example, a wellbore may be defined as comprising N segments characterized by the length, diameter, inclination angle, and azimuth direction of each segment and an indication of the order of the segments (i.e., first, second, etc.). 
     Wellbore parameters defined in this manner can then be used to mathematically produce a model of the entire wellbore trajectory. Formation material properties at various depths along the wellbore may also be defined and used. One of ordinary skill in the art will appreciate that wellbore parameters may include additional properties, such as friction of the walls of the wellbore, casing and cement properties, and wellbore fluid properties, among others, without departing from the scope of the disclosure. 
     “BHA parameters” may include one or more of the following: the type, location, and number of components included in the drilling tool assembly; the length, internal diameter of components, outer diameter of components, weight, and material properties of each component; the type, size, weight, configuration, and material properties of the drilling tool; and the type, size, number, location, orientation, and material properties of the cutting elements on the drilling tool. Material properties in designing a drilling tool assembly may include, for example, the strength, elasticity, and density of the material. It should be understood that drilling tool assembly design parameters may include any other configuration or material property of the drilling tool assembly without departing from the scope of the disclosure. 
     “Bit parameters,” which are a subset of BHA parameters, may include one or more of the following: bit type, size of bit, shape of bit, cutting structures on the bit, such as cutting type, cutting element geometry, number of cutting structures, and location of cutting structures. As with other components in the drilling tool assembly, the material properties of the bit may be defined. 
     “Drilling operating parameters” may include one or more of the following: the rotary table (or top drive mechanism), speed at which the drilling tool assembly is rotated (RPM), the downhole motor speed (if a downhole motor is included) and the hook load. Drilling operating parameters may further include drilling fluid parameters, such as the viscosity and density of the drilling fluid and pump pressure, for example. It should be understood that drilling operating parameters are not limited to these variables. In other embodiments, drilling operating parameters may include other variables, e.g., rotary torque and drilling fluid flow rate. Dip angle is the magnitude of the inclination of the formation from horizontal. Strike angle is the azimuth of the intersection of a plane with a horizontal surface. Additionally, drilling operating parameters for the purpose of drilling simulation may further include the total number of drill bit revolutions to be simulated, the total distance to be drilled, or the total drilling time desired for drilling simulation. 
     The parameters collected and/or analyzed by the downhole information system  150  may be shared with the computational device  140 , which may provide a more robust modeling of the RCD assembly  112 , a more accurate prediction model of the RCD assembly  112 , and/or may help with designing an RCD assembly. 
       FIG. 6  shows another example of a drilling system according to embodiments of the present disclosure. The drilling system  600  includes a drilling rig  602  that is used to support drilling operations. Many of the components used on a rig  602 , such as the kelly, power tongs, slips, draw works, and other equipment are not shown for ease of depiction. The rig  602  is used to support drilling and exploration operations in formation  604 . The borehole  606  is shown as being partially drilled, with the casing  608  set and cemented  609  into place. In one embodiment, a casing shutoff mechanism, or downhole deployment valve  610 , is installed in the casing  608  to optionally shutoff the annulus and effectively act as a valve to shut off the open hole section when the bit is located above the valve. 
     The drill string  612  supports a BHA  613  that includes a drill bit  620 , a mud motor, a MWD/LWD sensor suite  619 , including a pressure transducer  616  to determine the annular pressure, a check valve, to prevent backflow of fluid from the annulus. It also includes a telemetry package  622  that is used to transmit pressure, MWD/LWD as well as drilling information to be received at the surface. A BHA may utilize telemetry systems, such as radio frequency (RF), electromagnetic (EM) or drilling string transmission systems. 
     As noted above, the drilling process requires the use of a drilling fluid  650 , which may be stored in a reservoir  636 . A reservoir  636  may be a mud tank, pit, or any type of container that can accommodate a drilling fluid. The reservoir  636  is in fluid communication with one or more mud pumps  638  which pump the drilling fluid  650  through conduit  640 . An optional flow meter  652  can be provided in series with the one or more mud pumps, either upstream or downstream thereof. The conduit  640  is connected to the last joint of the drill string  612  that passes through an RCD assembly  642 . The RCD assembly  642  isolates the pressure in the annulus while still permitting drill string rotation. The fluid  650  is pumped down through the drill string  612  and the BHA  613  and exits the drill bit  620 , where it circulates the cuttings away from the bit  620  and returns them up the open hole annulus  615  and then the annulus formed between the casing  608  and the drill string  612 . The fluid  650  returns to the surface and goes through diverter  617  located in the RCD assembly  642 , through conduit  624  to an assisted well control system  660  and various solids control equipment  629 , such as, for example, a shaker. The assisted well control system  660  will be described in greater detail below. 
     The RCD assembly  642  may be mounted directly or indirectly on top of the wellhead or a blowout preventer (BOP) stack. The BOP stack may include an annular sealing element (annular BOP) and one or more sets of rams which may be operated to sealingly engage a pipe string disposed in the wellbore through the BOP or to cut the pipe string and seal the wellbore in the event of an emergency. 
     In conduit  624 , a second flow meter  626  may be provided. The flow meter  626  may be a mass-balance type or other high-resolution flow meter. It will be appreciated that by monitoring flow meters  626 ,  652  and the volume pumped by a backpressure pump  628 , the system may be able to determine the amount of fluid  650  being lost to the formation, or conversely, the amount of formation fluid leaking to the borehole  606 . Based on differences in the amount of fluid  650  pumped versus fluid  650  returned, the operator may be able to determine whether fluid  650  is being lost to the formation  604 , which may indicate that formation fracturing has occurred, i.e., a significant negative fluid differential. Likewise, a significant positive differential would be indicative of formation fluid entering into the wellbore. 
     After being treated by the solids control equipment  629 , the drilling fluid is directed to mud tank  636 . Drilling fluid from the mud tank  636  is directed through conduit  634  back to conduit  640  and to the drill string  612 . A backpressure line  644 , located upstream from the mud pumps  638 , fluidly connects conduit  634  to what is generally referred to as a backpressure system  646 . In one embodiment, a three-way valve may be placed in conduit  634 , which may allow fluid from the mud tank  636  to be selectively directed to the rig pump  638  to enter the drill string  612  or directed to the backpressure system  646 . In another embodiment, a three-way valve may be a controllable variable valve, allowing a variable partition of the total pump output to be delivered to the drill string  612  on the one side and to backpressure line  644  on the other side. This way, the drilling fluid can be pumped both into the drill string  612  and the backpressure system  646 . In one embodiment, a three-way fluid junction may be provided in conduit  634 , and a first variable flow restricting device may be provided between the three way fluid junction and the conduit  640  to the rig pump  638 , and a second variable flow restricting device may be provided between the three way fluid junction and the backpressure line  644 . Thus, the ability to provide adjustable backpressure during the entire drilling and completing processes may be provided. 
     The backpressure pump  628  may be provided with fluid from the reservoir through conduit  634 , which is in fluid communication with the reservoir  636 . While fluid from conduit  625 , located downstream from the assisted well control system  660  and upstream from solids control equipment  629  could be used to supply the backpressure system  646  with fluid, it will be appreciated that fluid from reservoir  636  has been treated by solids control equipment  629 . As such, the wear on backpressure pump  628  is less than the wear of pumping fluid in which drilling solids are still present. 
     In one embodiment, the backpressure pump  628  is capable of providing up to approximately 2200 psi (15168.5 kPa) of backpressure; though higher pressure capability pumps may be selected. The backpressure pump  628  pumps fluid into conduit  644 , which is in fluid communication with conduit  624  upstream of the assisted well control system  660 . As previously discussed, fluid from the annulus  615  is directed through conduit  624 . Thus, the fluid from backpressure pump  628  affects a backpressure on the fluid in conduit  624  and back into the annulus  615  of the borehole. The assisted well control system  660  may include an automatic choke  662  to controllably bleed off pressurized fluid from the annulus  615  or may use a fixed position choke. 
     Downhole information system  220  includes a computational device in communication with one or more sensors and/or equipment units of the drilling system  600 . For example, the downhole information system  220  may be in communication with one or more sensors disposed along the BHA  613 , one or more sensors disposed along the drill string  612  (such as pressure and temperature sensors), one or more sensors or control devices of the assisted well control system  660 , and one or more sensors or control devices of the backpressure system  646 . The downhole information system  220  may collect and analyze data about the drilling system, including but not limited to drilling operating parameters, wellbore parameters, and bottom hole assembly (BHA) parameters. The downhole information system  220  may be in communication with a computational device  210  used for analyzing, monitoring, and/or designing an RCD assembly according to embodiments of the present disclosure, where the downhole information system  220  may provide information about the drilling operation to the computational device  210 . In the embodiment shown in  FIG. 6 , the downhole information system  220  uses a computational device separate from but in communication with computational device  210 . However, in some embodiments, a single computational device may be used both for a downhole information system and for analyzing, monitoring, and/or designing an RCD assembly according to embodiments of the present disclosure. 
     A plurality of sensors, such as described in  FIGS. 1-4 , is disposed along one or more components of the RCD assembly  642  and is in communication with a programmable logic controller  200 . The sensors may send signals wirelessly to the programmable logic controller  200  (e.g., by sending signals to a receiver within the programmable logic controller) or may be wired to the programmable logic controller  200 . The programmable logic controller  200  may process the signals received from the sensors and provide measurement data to the computational device  210  having modeling software thereon. Using the measurement data, modeling software on the computational device may model, monitor, and/or analyze performance of one or more components of the RCD  642 . 
     Further, according to some embodiments of the present disclosure, a drilling system may include a data store for storing data related to an RCD assembly and at least one of the wellbore parameters, drilling performance, BHA parameters, and drilling operating parameters collected from the drilling operation. For example, a data store may store downhole data processed by a processor in a downhole information system. Downhole data may be collected from measurement devices disposed throughout a current drilling operation and processed by the processor of a downhole information system, and/or historical downhole data collected from remote and/or historical drilling operations may be collected and processed in the downhole information system. As used herein, the term historical downhole data may refer to downhole data collected from drilling operations occurring before a current drilling operation, from previously acquired downhole data collected and stored from a current drilling operation, from simulations of drilling operations, and/or from drilling operations conducted previous to or concurrently with but remote from a current drilling operation. 
     According to some embodiments, measurement data provided by a programmable logic controller from signals received from sensors along an RCD assembly may be stored in a data store. The data store may be in communication with a computational device, where the data store may be either located remotely from the computational device or located on the computational device. For example, the data store may be a storage unit or device, e.g., a file, file system, database, a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, a flash memory stick, or other system for storing data, located on a computational device, or the data store may be located remotely from a computational device. According to some embodiments, a data store may also hold historical measurement data collected from at least one remote RCD assembly, a simulation or model of an RCD assembly, a historical RCD assembly (i.e., an RCD assembly used in a drilling operation conducted before a current drilling operation), or other RCD assembly not being used in a current drilling operation. A data store may hold historical measurement data collected from at least one RCD assembly, which may be used to design a current RCD assembly. 
     Measurement data collected from sensors along an RCD assembly may be used to monitor operation of the RCD assembly during a current drilling operation. For example, according to embodiments of the present disclosure, a method for monitoring equipment in a current drilling operation may include receiving a plurality of signals from a plurality of sensors provided on at least one component of an RCD assembly into a programmable logic controller, providing measurement data from the plurality of signals using the programmable logic controller, and processing the measurement data using a modeling software to determine at least one condition of the RCD assembly. As discussed above, components of an RCD assembly on which sensors may be disposed may include, for example, one or more housings, one or more sealing components, one or more latches, and a bearing package. Conditions of the RCD assembly determined from the measurement data may include, for example, a health condition of one or more components of the RCD assembly or a status of one or more defined parameters of the RCD assembly. For example, a condition may include but is not limited to fatigue, cracking, galling of the sealing components of an RCD assembly which seal around the drill string, failure of a seal, such as between a sealing assembly and bearing package or between the bearing package and the RCD housing, slip (i.e., relative rotation between the drill string and seal of the RCD assembly, temperatures and/or pressures out of preferred operation window, and excessive vibration. 
     Modeling software may include, for example, Finite Element Analysis (FEA) software, Integrated Design and Engineering Analysis Software (IDEAS), or other software capable of processing measurement data, such as pressure, temperature, frequency, and position to analyze health conditions of a system and/or provide actionable advice given different operating conditions. For example, in some embodiments, modeling software may include a plurality of design parameters of a current RCD assembly inputted (e.g., size, shape and material properties of the components of the RCD assembly). The modeling software may provide a model of the current RCD assembly based on the inputted design parameters and/or use the inputted design parameters during analysis of the measurement data. For example, a modeling software may be used to model a current RCD assembly or component thereof (based on inputted design parameters) and the effect of selected measurement data on the current RCD assembly or component thereof (e.g., model a measured temperature and/or pressure effect on one or more sealing elements of a current RCD assembly, such as a sealing component or one or more seals disposed within the bearing package). 
     According to some embodiments, measurement data may be monitored to determine if there are any changes in one or more conditions of the RCD assembly. For example, in some embodiments, at least one pressure sensor may be positioned between two sealing components of a current RCD assembly. A change in the pressure measured between the two sealing components may indicate a negative health condition (such as failure, cracking or fatigue) of one or both of the sealing components or may indicate a change in the condition of one or more different components of drilling system. Comparing changes in measurement data collected from a current RCD assembly with one or more parameters of the drilling operation may be used to determine whether the change in measurement data resulted from a change in one or more conditions of the RCD assembly or if the change in measurement data resulted from one or more parameters of the drilling operation. For example, a large change in measured pressure from measurement data collected from the RCD assembly may have resulted from a change in the fluid flow rate of the drilling system or may have resulted from a change in condition of one or more components in the RCD assembly. 
     In some embodiments, measurement data may be compared with limits of the inputted design parameters for one or more of the RCD assembly components. For example, in some embodiments, design parameters related to one or more sealing components or seals may be inputted into the modeling software, which may be used to provide one or more pressure and/or temperature limits (e.g., a maximum pressure and/or temperature that a sealing element may be exposed to before failure or degradation of properties). Pressure and/or temperature measurement data may be monitored and analyzed by the modeling software to determine if pressure and/or temperature conditions fall outside of the limits for one or more sealing elements. 
     Further, according to some embodiments, one or more drilling parameters of the current drilling operation may be inputted into the modeling software. For example, wellbore parameters, drilling performance parameters, BHA parameters, and drilling operating parameters collected from the current drilling operation, such as by using a downhole information system, as described above, may be inputted into the modeling software. Drilling parameters may be useful in analyzing and monitoring performance of an RCD assembly used in the current drilling operation. For example, pressure measurement data collected from a current RCD assembly (e.g., pressure within a bearing package of the RCD assembly or pressure within the RCD assembly housing) may be compared with pressure downhole data (e.g., pressure of fluid below the RCD assembly and/or pressure diverted from the RCD assembly) to determine any changes in pressure differentials. Changes in relative pressures within components of the RCD assembly and within components of the drilling system outside the RCD assembly may indicate, for example, a seal failure, a valve failure, and/or a leak. 
     According to some embodiments, at least one limit on the value of measurement data being collected may be set into the programmable logic controller, such as a maximum or minimum value of the measurement data (e.g., a maximum pressure value, maximum and/or minimum temperature value, maximum displacement, maximum vibration, etc.) being collected from sensors disposed along a RCD assembly in operation. In such embodiments, an alert may be provided when measurement data is processed outside the set limit(s). For example, if measurement data related to the vibration (e.g., amplitude and/or frequency of the vibration) of the RCD assembly is processed by the programmable logic controller (e.g., in real-time) that is greater than a set maximum vibration limit, an alert may be sent by the programmable logic controller indicating such occurrence. In another example, a maximum pressure limit within a bearing package of an RCD assembly may be set, where an alert may be provided when the measurement data collected from the sensors disposed along the RCD assembly includes at least one pressure value within the bearing package that is greater than the set maximum pressure limit. 
     One or more different actions may be taken when an alarm is provided, or no action may be taken. For example, in some embodiments, at least one drilling parameter of the drilling operation may be altered when an alert is provided. The drilling parameter(s) being changed and the magnitude of the change in response to the alert may be selected to account for the change in condition in the RCD assembly or to bring the measurement data values being collected within the set limit(s). For example, upon receiving an alert that the pressure on the lower side of the RCD assembly is over a set maximum pressure limit, one or more drilling parameters may be altered to lower the pressure, such as by increasing the rate of fluid being diverted from the RCD assembly. 
       FIG. 7  shows an example of a method according to embodiments of the present disclosure. As shown, one or more drilling parameters for a current drilling operation may be set  700 , which may include, for example, wellbore parameters, BHA parameters, drilling operating parameters, and drilling performance parameters. For example, a drilling operator may set one or more of the drilling parameters, one or more drilling parameters may be set during design and manufacture of the drilling system, and one or more of the drilling parameters may be set automatically using an optimization program. Measurement data collected from sensors disposed along an RCD assembly in the current drilling operation may be monitored  710  according to methods disclosed herein. Changes in the measurement data may be analyzed  720  to determine the conditions of one or more components of the RCD assembly and/or to compare with other parameters of the current drilling system. In some embodiments, one or more parameters of the current drilling operation may be altered  730  in response to the change in measurement data collected from the sensors of the RCD assembly. For example, parameters of the drilling operation that may be altered in response to changes in measurement data collected from the RCD assembly may include but are not limited to altering the fluid flow rate of the fluid being pumped through the drill string, altering operation of one or more valves and/or pumps affecting the flow of fluid being diverted from the annulus (e.g., in response to increases in pressure measured from the RCD assembly), and/or altering the RPM of the drilling tool assembly (e.g., in response to increases in amount of vibration measured from the RCD assembly). 
     In one example according to embodiments of the present disclosure, the position of a drill string relative to a sealing component in a current RCD assembly may be measured using at least one position sensor. The position sensor(s) may send signals to a programmable logic controller, which may process the signals and send measurement data related to the position of the drill string relative to the sealing component to a computational device having modeling software. In another example according to embodiments of the present disclosure, at least one frequency sensor may be positioned on at least one of a sealing component and/or a bearing package of a current RCD assembly and a drill string. The frequency sensor(s) sends signals to a programmable logic controller, which may process the signals and send measurement data related to the rotational speed of the sealing component, bearing package and/or drill string to a computational device having modeling software. Modeling software may be used to analyze collected position measurement data and/or collected frequency measurement data, for example, to determine differences in movement between the monitored components or if slip is occurring between the drill string and sealing component. For example, frequency sensors may be disposed on a bearing package or sealing component and on a drill string extending through the RCD assembly to measure the rotational speed of each, where a difference in rotational speed between the sealing component or bearing package and the drill string may indicate slip. 
     According to some embodiments, measurement data collected from sensors along an RCD assembly in a current drilling operation may be used to predict performance of one or more elements of the RCD assembly. For example, measurement data related to a bearing package of an RCD assembly (e.g., pressure measured inside of the bearing package) may be used to predict failure of a sealing component of the RCD assembly. In some embodiments, measurement data collected from sensors of a current RCD assembly may be compared with historical measurement data from RCD assemblies having one or more similar design parameters and/or RCD assemblies that have operated in similar environments. For example, historical measurement data from an RCD assembly that failed due to determined temperature and pressure conditions may be used to predict when a current RCD assembly exposed to the same or similar temperature and pressure conditions may fail. 
     Further, significant expense is involved in the design and manufacture of drilling and operating equipment. As such, in order to optimize performance of a drilling system, engineers may consider a variety of factors. For example, when designing a drilling system, engineers may consider a rock profile (e.g., the type of rock or the geologic characteristics of an earth formation), different forces acting on the drilling system, drilling performance parameters, drill bit parameters, and/or wellbore parameters, among many others. 
     Methods disclosed herein may be used to design an RCD assembly. For example, according to embodiments of the present disclosure, a method for designing equipment in a current drilling operation may include obtaining previously acquired measurement data from a plurality of sensors disposed on at least one RCD assembly, where each RCD assembly operates under a plurality of drilling parameters, processing the measurement data using a modeling software to determine at least one condition of the RCD assembly(s), storing the condition(s) as being associated with the drilling parameters under which the RCD assembly operated, and selecting at least one design parameter of a current RCD assembly based on drilling parameters of the current drilling operation and the stored condition(s). Previously acquired measurement data may include historical measurement data collected from one or more RCD assemblies or may include measurement data collected from one or more current RCD assemblies (used in a current drilling system) that has been stored for later use. 
     Storing a determined condition as being associated with the drilling parameters under which the RCD assembly operated may include, for example, storing the related data in a searchable database. For example, a database may include a plurality of determined conditions of RCD assemblies and the parameters under which the conditions occurred, where either a condition type may be searched for or a parameter may be searched for. When a searched condition type is presented, the associated parameters under which the condition type has occurred in the past may be presented in the search results. Likewise, when a searched parameter (or combination of parameters) is presented, the associated conditions that have occurred under the parameter(s) in the past may be presented in the search results. Determined conditions may include but are not limited to lifetimes of one or more components of the RCD assembly, failure types of one or more components of the RCD assembly, measurement data values such as amount of displacement and amount of vibration, drill string slip, and yes/no logic-type information, such as whether the bearing package is rotating as designed, whether a latch is in the latched position, whether a pressure is being maintained between seals, and others. 
     According to embodiments of the present disclosure, an RCD assembly may be designed for a current drilling operation (e.g., as a replacement RCD assembly or to repair a current RCD assembly). For example, a method for designing an RCD assembly may include selecting stored drilling parameters having a plurality of shared values with the drilling parameters of the current drilling operation, such as from a database or other data store type. At least one optimized condition associated with the selected stored drilling parameters may be determined. For example, as discussed above, conditions associated with drilling parameters may be stored in a searchable database, where either one or a combination of drilling parameters or a condition may be searched, and the associated conditions or parameters may be presented in the search results. From the search results, a user may select an optimized result, or a software program may automatically select an optimized result, for example. At least one design parameter of a current RCD assembly may then be selected based on the design parameters of the RCD assembly having the optimized condition. 
     For example, to design an RCD assembly that may be capable of functioning under a first and second drilling parameter of a current drilling operation (e.g., under a certain pressure from the fluid in the annular space below the RCD assembly, with a certain drill string rpm, or other drilling parameters), stored data for drilling systems having the first and second drilling parameters may be searched. According to other embodiments, one or more than two drilling parameters may be selected when designing an RCD assembly. The results of the search may include one or more conditions of the RCD assemblies used in the drilling systems having the first and second drilling parameters, from which one or more optimally performing RCD assemblies (performing under the first and second drilling parameters) may be determined. One or more design parameters of the optimally performing RCD assemblies may then be used to design the current RCD assembly (or to repair and/or replace one or more components of a current RCD assembly). 
     Upon selecting one or more design parameters of an RCD assembly, the RCD assembly may be designed and its performance may be predicted. For example, in some embodiments, the modeling software may model the designed RCD assembly, and the modeled RCD assembly may be simulated in selected drilling systems (where the drilling system may be defined in the simulation by wellbore parameters, drilling operation parameters, BHA parameters, etc.) to predict the performance of the designed RCD assembly. In some embodiments, performance of previously used RCD assemblies having the same or similar design parameters as those of the designed RCD assembly and operated under the same or similar drilling conditions may be analyzed to predict performance of the designed RCD assembly. 
     According to some embodiments of the present disclosure, at least one condition of a current RCD assembly may be predicted operating under one or more altered drilling parameters. Predicting conditions of an RCD assembly under altered drilling parameters may include selecting stored drilling parameters having shared values with the altered drilling parameters and determining the conditions associated with the selected stored drilling parameters. For example, downhole data stored in a data store may be searched for drilling systems having the altered drilling parameters and RCD assemblies with the same or similar design parameters of the current RCD assembly, where the prediction of the current RCD assembly conditions may be based on the stored conditions of the RCD assemblies in the drilling systems having the altered drilling parameters. In other embodiments, predicting conditions of an RCD assembly under altered drilling parameters may include simulating the RCD assembly under the altered drilling parameters using modeling and/or simulation software. 
     Prediction of RCD assembly performance under altered drilling parameters may be useful in situations when the drilling system changes, such as when a new type of formation is encountered and one or more drilling operation parameters are changed to drill through the new formation type, during directional drilling, when one or more components of the drilling system fails, during heaves in offshore drilling, and others. 
     While the claimed subject matter has been described with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the claimed subject matter as disclosed herein. Accordingly, the scope of the claimed subject matter should be limited only by the attached claims.