Patent Publication Number: US-9422776-B2

Title: Rotating control device having jumper for riser auxiliary line

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims benefit of U.S. Provisional Patent Application Ser. No. 61/929,342, filed Jan. 20, 2014, which is herein incorporated by reference. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention generally relates to a rotating control device having a jumper for a riser auxiliary line. 
     2. Description of the Related Art 
     In wellbore construction and completion operations, a wellbore is formed to access hydrocarbon-bearing formations (e.g., crude oil and/or natural gas) by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is temporarily hung from the surface of the well. A cementing operation is then conducted in order to fill the annulus with cement. The casing string is cemented into the wellbore by circulating cement into the annulus defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons. 
     Deep water offshore drilling operations are typically carried out by a mobile offshore drilling unit (MODU), such as a drill ship or a semi-submersible, having the drilling rig aboard and often make use of a marine riser extending between the wellhead of the well that is being drilled in a subsea formation and the MODU. The marine riser is a tubular string made up of a plurality of tubular sections that are connected in end-to-end relationship. The riser allows return of the drilling mud with drill cuttings from the hole that is being drilled. Also, the marine riser is adapted for being used as a guide means for lowering equipment (such as a drill string carrying a drill bit) into the hole. 
     SUMMARY OF THE INVENTION 
     The present invention generally relates to a rotating control device having a jumper for a riser auxiliary line. In one embodiment, a rotating control device housing includes an upper riser flange; a lower riser flange; a latch section for receiving a bearing assembly and connected to the upper riser flange; a port section connected to the latch section by a flanged connection, having an outlet for discharging fluid flow diverted by the bearing assembly, and connected to the lower riser flange; and a jumper connected to the upper and lower riser flanges. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
         FIGS. 1A-1D  illustrate an offshore drilling system in a riser deployment mode, according to one embodiment of the present invention. 
         FIG. 2A  illustrate a rotating control device (RCD) housing of the drilling system.  FIGS. 2B-2F  illustrate riser flanges of the RCD housing. 
         FIGS. 3A-3C  illustrate the offshore drilling system in an overbalanced drilling mode. 
         FIG. 4  illustrates the offshore drilling system in a managed pressure drilling mode. 
         FIG. 5  illustrates an alternative RCD housing for use with the drilling system, according to another embodiment of the invention. 
         FIG. 6  illustrates an alternative RCD housing for use with the drilling system, according to another embodiment of the invention. 
     
    
    
     To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures. It is contemplated that elements disclosed in one embodiment may be beneficially utilized on other embodiments without specific recitation. 
     DETAILED DESCRIPTION 
       FIGS. 1A-1D  illustrate an offshore drilling system  1  in a riser deployment mode, according to one embodiment of the present invention. The drilling system  1  may include a mobile offshore drilling unit (MODU)  1   m , such as a semi-submersible, a drilling rig  1   r , a fluid handling system  1   h  (only partially shown, see  FIG. 3A ), a fluid transport system  1   t  (only partially shown, see  FIGS. 3A-3C ), and a pressure control assembly (PCA)  1   p  (see  FIG. 1B ). The MODU  1   m  may carry the drilling rig  1   r  and the fluid handling system  1   h  aboard and may include a moon pool, through which operations are conducted. The semi-submersible MODU  1   m  may include a lower barge hull which floats below a surface (aka waterline)  2   s  of sea  2  and is, therefore, less subject to surface wave action. Stability columns (only one shown) may be mounted on the lower barge hull for supporting an upper hull above the waterline. The upper hull may have one or more decks for carrying the drilling rig  1   r  and fluid handling system  1   h . The MODU  1   m  may further have a dynamic positioning system (DPS) (not shown) or be moored for maintaining the moon pool in position over a subsea wellhead  50 . 
     Alternatively, the MODU  1   m  may be a drill ship. Alternatively, a fixed offshore drilling unit or a non-mobile floating offshore drilling unit may be used instead of the MODU  1   m.    
     The drilling rig  1   r  may include a derrick  3  having a rig floor  4  at its lower end having an opening corresponding to the moonpool. The rig  1   r  may further include a traveling block  6  be supported by wire rope  7 . An upper end of the wire ripe  7  may be coupled to a crown block  8 . The wire rope  7  may be woven through sheaves of the blocks  6 ,  8  and extend to drawworks  9  for reeling thereof, thereby raising or lowering the traveling block  6  relative to the derrick  3 . A running tool  38  may be connected to the traveling block  6 , such as by a rig compensator  36 . Alternatively, the rig compensator may be disposed between the crown block  8  and the derrick  3 . 
     A fluid transport system it (shown in  FIG. 3A ) may include an upper marine riser package (UMRP)  20  (only partially shown, see  FIG. 3A ), a marine riser  25 , one or more auxiliary lines  27 ,  28 , such as a booster line  27  and a choke line  28 , and a drill string  10  (in drilling mode, see  FIGS. 3A-3C ). Additionally, the auxiliary lines  27 ,  28  may further include a kill line (not shown) and/or one or more hydraulic lines for charging the accumulators  44 . During deployment, the PCA  1   p  may be connected to a wellhead  50  located adjacent to a floor  2   f  of the sea  2 . 
     A conductor string  51  may be driven into the seafloor  2   f . The conductor string  51  may include a housing and joints of conductor pipe connected together, such as by threaded connections. Once the conductor string  51  has been set, a subsea wellbore  55  (shown in  FIG. 3C ) may be drilled into the seafloor  2   f  and a casing string  52  (shown in  FIG. 3C ) may be deployed into the wellbore. The casing string  52  may include a wellhead housing and joints of casing connected together, such as by threaded connections. The wellhead housing may land in the conductor housing during deployment of the casing string  52 . The casing string  52  may be cemented  53  into the wellbore  55  (shown in  FIG. 3C ). The casing string  52  may extend to a depth adjacent a bottom of an upper formation  54   u  (shown in  FIG. 3C ). The upper formation  54   u  may be non-productive and a lower formation  54   b  may be a hydrocarbon-bearing reservoir (shown in  FIG. 3C ). Alternatively, the lower formation  54   b  may be environmentally sensitive, such as an aquifer, or unstable. Although shown as vertical, the wellbore  55  may include a vertical portion and a deviated, such as horizontal, portion. 
     The PCA  1   p  may include a wellhead adapter  40   b , one or more flow crosses  41   u,m,b , one or more blow out preventers (BOPs)  42   a,u,b , a lower marine riser package (LMRP), one or more accumulators  44 , and a receiver  46 . The LMRP may include a control pod  48 , a flex joint  43 , and a connector  40   u . The wellhead adapter  40   b , flow crosses  41   u,m,b , BOPs  42   a,u,b , receiver  46 , connector  40   u , and flex joint  43 , may each include a housing having a longitudinal bore therethrough and may each be connected, such as by flanges, such that a continuous bore is maintained therethrough. The bore may have drift diameter, corresponding to a drift diameter of the wellhead  50 . 
     Each of the connector  40   u  and wellhead adapter  40   b  may include one or more fasteners, such as dogs, for fastening the LMRP to the BOPs  42   a,u,b  and the PCA  1   p  to an external profile of the wellhead housing, respectively. Each of the connector  40   u  and wellhead adapter  40   b  may further include a seal sleeve for engaging an internal profile of the respective receiver  46  and wellhead housing. Each of the connector  40   u  and wellhead adapter  40   b  may be in electric or hydraulic communication with the control pod  48  and/or further include an electric or hydraulic actuator and an interface, such as a hot stab, so that a remotely operated subsea vehicle (ROV) (not shown) may operate the actuator for engaging the dogs with the external profile. 
     The LMRP may receive a lower end of the riser  25  and connect the riser to the PCA  1   p . The control pod  48  may be in electric, hydraulic, and/or optical communication with a rig controller (not shown) onboard the MODU  1   m  via an umbilical  49 . The control pod  48  may include one or more control valves (not shown) in communication with the BOPs  42   a,u,b  for operation thereof. Each control valve may include an electric or hydraulic actuator in communication with the umbilical  49 . The umbilical  49  may include one or more hydraulic or electric control conduit/cables for the actuators. The accumulators  44  may store pressurized hydraulic fluid for operating the BOPs  42   a,u,b . Additionally, the accumulators  44  may be used for operating one or more of the other components of the PCA  1   p . The umbilical  49  may further include hydraulic, electric, and/or optic control conduit/cables for operating various functions of the PCA  1   p . The rig controller may operate the PCA  1   p  via the umbilical  49  and the control pod  48 . 
     A lower end of the booster line  27  may be connected to a branch of the flow cross  41   u  by a shutoff valve  45   a . A booster manifold may also connect to the booster line lower end and have a prong connected to a respective branch of each flow cross  41   m,b . Shutoff valves  45   b,c  may be disposed in respective prongs of the booster manifold. Alternatively, the kill line may be connected to the branches of the flow crosses  41   m,b  instead of the booster manifold. An upper end of the booster line  27  may be connected to an outlet of a booster pump (not shown) and an upper end of the choke line may be connected to a rig choke (not shown). A lower end of the choke line  28  may have prongs connected to respective second branches of the flow crosses  41   m,b . Shutoff valves  45   d,e  may be disposed in respective prongs of the choke line lower end. 
     A pressure sensor  47   a  may be connected to a second branch of the upper flow cross  41   u . Pressure sensors  47   b,c  may be connected to the choke line prongs between respective shutoff valves  45   d,e  and respective flow cross second branches. Each pressure sensor  47   a - c  may be in data communication with the control pod  48 . The lines  27 ,  28  and may extend between the MODU  1   m  and the PCA  1   p  by being fastened to flanged connections  25   f  between joints of the riser  25 . The umbilical  49  may also extend between the MODU  1   m  and the PCA  1   p . Each shutoff valve  45   a - e  may be automated and have a hydraulic actuator (not shown) operable by the control pod  48  via fluid communication with a respective umbilical conduit or the LMRP accumulators  44 . Alternatively, the valve actuators may be electrical or pneumatic. 
     Once deployed, the riser  25  may extend from the PCA  1   p  to the MODU  1   m  and may connect to the MODU via the UMRP  20  (see  FIG. 3A ). The UMRP  20  may include a diverter  21  (only housing shown), a flex joint  22  (see  FIG. 3A ), a slip (aka telescopic) joint  23  upon deployment (see  FIG. 3A ), a tensioner  24 , and a rotating control device (RCD) housing  60 . A lower end of the RCD housing  60  may be connected to an upper end of the riser  25 , such as by a flanged connection. The slip joint  23  may include an outer barrel connected to an upper end of the RCD housing  60 , such as by a flanged connection, and an inner barrel connected to the flex joint  22 , such as by a flanged connection. The outer barrel may also be connected to the tensioner  24 , such as by a tensioner ring, and may further include a termination ring for connecting upper ends of the lines  27 ,  28  to respective hoses  27   h ,  28   h  leading to the MODU  1   m  (see  FIG. 3A ). 
     The flex joint  22  may also connect to a mandrel of the diverter  21 , such as by a flanged connection. The diverter mandrel may be hung from the diverter housing during deployment of the riser  25 . The diverter housing may also be connected to the rig floor  4 , such as by a bracket. The slip joint  23  may be operable to extend and retract in response to heave of the MODU  1   m  relative to the riser  25  while the tensioner  24  may reel wire rope in response to the heave, thereby supporting the riser  25  from the MODU  1   m  while accommodating the heave. The flex joints  23 ,  43  may accommodate respective horizontal and/or rotational (aka pitch and roll) movement of the MODU  1   m  relative to the riser  25  and the riser relative to the PCA  1   p . The riser  25  may have one or more buoyancy modules (not shown) disposed therealong to reduce load on the tensioner  24 . 
     In operation, a lower portion of the riser  25  may be assembled using the running tool  38  and a riser spider (not shown). The riser  25  may be lowered through a rotary table  37  located on the rig floor  4  while coupled to the RCD housing  60 , and thus, assembly within moonpool is minimized or eliminated. The PCA  1   p  may be lowered through the moonpool by assembling joints of the riser  25  using the flanges  25   f . Once the PCA  1   p  nears the wellhead  50 , the RCD housing  60  may be connected to an upper end of the riser  25  using the running tool  38  and spider. The RCD housing  60  may then be lowered through the rotary table  37  into the moonpool. The RCD housing  60  may then be lowered through the moonpool by assembling the other UMRP components (slip joint locked). The diverter mandrel may be landed into the diverter housing and the tensioner  24  connected to the tensioner ring. The tensioner  24  and slip joint  23  may then be operated to land the PCA  1   p  onto the wellhead  50  and the PCA latched to the wellhead. 
     The pod  48  and umbilical  49  may be deployed with the PCA  1   p  as shown. Alternatively, the pod  48  may be deployed in a separate step after the riser deployment operation. In this alternative, the pod  48  may be lowered to the PCA  1   p  using the umbilical  49  and then latched to a receptacle (not shown) of the LMRP. Alternatively, the umbilical  49  may be secured to the riser  25 . 
       FIG. 2A  illustrates the RCD housing  60 . The RCD housing  60  may be tubular and have one or more sections  61 - 64  connected together, such as by flanged connections. The housing sections may include an upper spool  61 , a latch section  62 , a port section  63 , and a lower spool  64 . The RCD housing  60  may further include one or more auxiliary jumpers  27   j ,  28   j  for routing the booster line  27  and the choke line  28  around the latch  62  and port sections  63 . 
     The lower spool  64  may be tubular and include an upper flange  66   u , a lower flange  65   m , and a body connecting the flanges, such as by being welded thereto. The upper flange  66   u  may mate with a lower flange of the port section  63 , thereby connecting the two components. The lower flange  65   m  may mate with an upper flange  65   f  of the riser  25 , thereby connecting the two components. The upper spool  61  may be tubular and include an upper flange  65   f , a lower flange  66   b , and a body connecting the flanges, such as by being welded thereto. The upper flange  65   f  may mate with a lower flange of the slip joint  23 , thereby connecting the two components. The lower flange  66   b  may mate with an upper flange of the latch section  62 , thereby connecting the two components. The upper flanges  66   u  and the lower flange  66   b  may be the same. 
     Each jumper  27   j ,  28   j  may be pipe made from a metal or alloy, such as steel, stainless steel, or nickel based alloy. Alternatively, each jumper  27   j ,  28   j  may be a hose made from a flexible polymer material, such as a thermoplastic or elastomer, or may be a metal or alloy bellows. Each hose may or may not be reinforced, such as by metal or alloy cords. 
       FIGS. 2B-2F  illustrate the flanges  65   m,f . Each flange  65   m,f  may have a bore  281  formed therethrough, a respective neck portion  280   m,f , a respective rim portion  282   m,f , and a coupling  285 ,  286  for each of the booster and choke lines  27 ,  28  or jumpers  27   j ,  28   j . Each rim portion  282   m,f  may have sockets and holes (not shown) formed therethrough and spaced therearound in an alternating fashion. The holes may receive fasteners  291 , such as bolts or studs and nuts. Each rim portion  282   m,f  may further have a seal bore  283  formed in an inner surface thereof and a shoulder formed at the end of the seal bore. A seal sleeve  284  may carry one or more seals  280  for each flange  65   m,f  along an outer surface thereof and be fastened to each male flange  65   m  with the seal therefore in engagement with the seal bore thereof. The seal bore of each female flange  65   f  may receive the respective seal sleeve  284  and the sleeve may be trapped between the seal bore shoulders. 
     Each flange socket may receive the respective coupling  285 ,  286 . Each coupling  285 ,  286  may have an end  293 ,  294  for connection to the respective booster and choke lines  27 ,  28  or jumpers  27   j ,  28   j , such as by welding. Each female coupling  286  may be retained in the respective flange socket by mating shoulders. Each male coupling  285  may have a nut  287  fastened thereto, such as by threads. The nut  287  may have a shoulder formed in an outer surface thereof for retaining the male coupling  285  in the respective flange socket. Each female coupling  286  may have a seal bore formed in an inner surface thereof for receiving a complementary stinger of the respective male coupling  285 . The seal bore may carry one or more seals  288  for sealing an interface between the respective stinger. The stabbing depth of the male coupling  285  into the female coupling  286  may be adjusted using the nut  287 . 
     Alternatively, each male coupling may carry the seals instead of the respective female coupling. Alternatively, the male-down convention illustrated in  FIG. 1B  may be reversed. 
       FIGS. 3A-3C  illustrate the offshore drilling system  1  in an overbalanced drilling mode. Once the riser  25 , PCA  1   p , and UMRP  20  have been deployed, drilling of the lower formation  54   b  may commence. The running tool  38  may be replaced by a top drive  5  and a fluid handling system  1   h  may be installed. The drill string  10  may be deployed into the wellbore  55  through the riser  25 , PCA  1   p , UMRP  20  and casing  52 . 
     The drilling rig  1   r  may further include a rail (not shown) extending from the rig floor  4  toward the crown block  8 . The top drive  5  may include an extender (not shown), motor, an inlet, a gear box, a swivel, a quill, a trolley (not shown), a pipe hoist (not shown), and a backup wrench (not shown). The top drive motor may be electric or hydraulic and have a rotor and stator. The motor may be operable to rotate the rotor relative to the stator which may also torsionally drive the quill via one or more gears (not shown) of the gear box. The quill may have a coupling (not shown), such as splines, formed at an upper end thereof and torsionally connecting the quill to a mating coupling of one of the gears. Housings of the motor, swivel, gear box, and backup wrench may be connected to one another, such as by fastening, so as to form a non-rotating frame. The top drive  5  may further include an interface (not shown) for receiving power and/or control lines. 
     The trolley may ride along the rail, thereby torsionally restraining the frame while allowing vertical movement of the top drive  5  with the travelling block. The traveling block may be connected to the frame via the rig compensator to suspend the top drive from the derrick  3 . The swivel may include one or more bearings for longitudinally and rotationally supporting rotation of the quill relative to the frame. The inlet may have a coupling for connection to a Kelly hose  17   h  and provide fluid communication between the Kelly hose and a bore of the quill. The quill may have a coupling, such as a threaded pin, formed at a lower end thereof for connection to a mating coupling, such as a threaded box, at a top of the drill string  10 . 
     The drill string  10  may include a bottomhole assembly (BHA)  10   b  and joints of drill pipe  10   p  connected together, such as by threaded couplings. The BHA  10   b  may be connected to the drill pipe  10   p , such as by a threaded connection, and include a drill bit  12  and one or more drill collars  11  connected thereto, such as by a threaded connection. The drill bit  12  may be rotated  13  by the top drive  5  via the drill pipe  10   p  and/or the BHA  10   b  may further include a drilling motor (not shown) for rotating the drill bit. The BHA  10   b  may further include an instrumentation sub (not shown), such as a measurement while drilling (MWD) and/or a logging while drilling (LWD) sub. 
     The fluid handling system  1   h  may include a fluid tank  15 , a supply line  17   p,h , one or more shutoff valves  18   a - f , an RCD return line  26 , a diverter return line  29 , a mud pump  30 , a hydraulic power unit (HPU)  32   h , a hydraulic manifold  32   m , a cuttings separator, such as shale shaker  33 , a pressure gauge  34 , the programmable logic controller (PLC)  35 , a return bypass spool  36   r , a supply bypass spool  36   s . A first end of the return line  29  may be connected to an outlet of the diverter  21  and a second end of the return line may be connected to the inlet of the shaker  33 . A lower end of the RCD return line  19  may be connected to an outlet of the RCD  63  and an upper end of the return line may have shutoff valve  18   c  and be blind flanged. An upper end of the return bypass spool  36   r  may be connected to the shaker inlet and a lower end of the return bypass spool may have shutoff valve  18   b  and be blind flanged. A transfer line  16  may connect an outlet of the fluid tank  15  to the inlet of the mud pump  30 . A lower end of the supply line  17   p,h  may be connected to the outlet of the mud pump  30  and an upper end of the supply line may be connected to the top drive inlet. The pressure gauge  34  and supply shutoff valve  18   f  may be assembled as part of the supply line  17   p,h . A first end of the supply bypass spool  36   s  may be connected to the outlet of the mud pump  30   d  and a second end of the bypass spool may be connected to the standpipe  17   p  and may each be blind flanged. The shutoff valves  18   d,e  may be assembled as part of the supply bypass spool  36   s.    
     In the overbalanced drilling mode, the mud pump  30  may pump the drilling fluid  14   d  from the transfer line  16 , through the pump outlet, standpipe  17   p  and Kelly hose  17   h  to the top drive  5 . The drilling fluid  14   d  may flow from the Kelly hose  17   h  and into the drill string  10  via the top drive inlet. The drilling fluid  14   d  may flow down through the drill string  10  and exit the drill bit  12 , where the fluid may circulate the cuttings away from the bit and carry the cuttings up the annulus  56  formed between an inner surface of the casing  52  or wellbore  55  and the outer surface of the drill string  10 . The returns  14   r  may flow through the annulus  56  to the wellhead  50 . The returns  14   r  may continue from the wellhead  50  and into the riser  25  via the PCA  1   p . The returns  14   r  may flow up the riser  25  to the diverter  21 . The returns  14   r  may flow into the diverter return line  29  via the diverter outlet. The returns  14   r  may continue through the diverter return line  29  to the shale shaker  33  and be processed thereby to remove the cuttings, thereby completing a cycle. As the drilling fluid  14   d  and returns  14   r  circulate, the drill string  10  may be rotated  13  by the top drive  5  and lowered by the traveling block, thereby extending the wellbore  55  into the lower formation. 
     The drilling fluid  14   d  may include a base liquid. The base liquid may be base oil, water, brine, or a water/oil emulsion. The base oil may be diesel, kerosene, naphtha, mineral oil, or synthetic oil. The drilling fluid  14   d  may further include solids dissolved or suspended in the base liquid, such as organophilic clay, lignite, and/or asphalt, thereby forming a mud. 
       FIG. 4  illustrates the offshore drilling system  1  in a managed pressure drilling mode. Should an unstable zone in the lower formation  54   b  be encountered, the drilling system  1  may be shifted into managed pressure mode. To shift the drilling system  1 , a managed pressure return spool (not shown) may be connected to the RCD return line  26  and the bypass return spool  36   r . The managed pressure return spool may include a returns pressure sensor, a returns choke, a returns flow meter, and a gas detector. A managed pressure supply spool (not shown) may be connected to the supply bypass spool  36   s . The managed pressure supply spool may include a supply pressure sensor and a supply flow meter. Each pressure sensor may be in data communication with the PLC  35 . The returns pressure sensor may be operable to measure backpressure exerted by the returns choke. The supply pressure sensor may be operable to measure standpipe pressure. 
     The returns flow meter may be a mass flow meter, such as a Coriolis flow meter, and may be in data communication with the PLC  35 . The returns flow meter may be connected in the spool downstream of the returns choke and may be operable to measure a flow rate of the returns  14   r . The supply flow meter may be a volumetric flow meter, such as a Venturi flow meter. The supply flow meter may be operable to measure a flow rate of drilling fluid  14   d  supplied by the mud pump  30  to the drill string  10  via the top drive  5 . The PLC  35  may receive a density measurement of the drilling fluid  14   d  from a mud blender (not shown) to determine a mass flow rate of the drilling fluid. The gas detector may include a probe having a membrane for sampling gas from the returns  14   r , a gas chromatograph, and a carrier system for delivering the gas sample to the chromatograph. Alternatively, the supply flow meter may be a mass flow meter. 
     Additionally, a degassing spool (not shown) may be connected to a second return bypass spool (not shown). The degassing spool may include automated shutoff valves at each end and a mud-gas separator (MGS). A first end of the degassing spool may be connected to the return spool between the gas detector and the shaker  33  and a second end of the degasser spool may be connected to an inlet of the shaker. The MGS may include an inlet and a liquid outlet assembled as part of the degassing spool and a gas outlet connected to a flare or a gas storage vessel. The PLC  35  may utilize the flow meters to perform a mass balance between the drilling fluid and returns flow rates and activate the degassing spool in response to detecting a kick of formation fluid. 
     The RCD  63  may be shifted from idle mode ( FIG. 3A ) to active mode ( FIG. 4 ) by retrieving the protector sleeve and replacing the protector sleeve with the bearing assembly. Once the RCD  63  has been shifted, drilling may recommence in the managed pressure mode. The RCD  63  may divert the returns  14   r  into the RCD return line  26  and through the managed pressure return spool to the shaker  33 . During drilling, the PLC  35  may perform the mass balance and adjust the returns choke accordingly, such as tightening the choke in response to a kick and loosening the choke in response to loss of the returns. As part of the shift to managed pressure mode, a density of the drilling fluid  14   d  may be reduced to correspond to a pore pressure gradient of the lower formation  54   b.    
     The RCD  63  may include the housing  60 , a piston, a latch, a protector sleeve (shown in  FIG. 1B ) and the bearing assembly. The bearing assembly may include a bearing pack, a housing seal assembly, one or more strippers  71 , and a catch sleeve. The bearing assembly may be selectively longitudinally and torsionally connected to the housing by engagement of the latch with the catch sleeve. The latch section  62  may have hydraulic ports in fluid communication with the piston and an interface of the RCD  63 . The bearing pack may support the strippers from the sleeve such that the strippers may rotate relative to the housing (and the sleeve). The bearing pack may include one or more radial bearings, one or more thrust bearings, and a self contained lubricant system. The bearing pack may be disposed between the strippers and be housed in and connected to the catch sleeve, such as by a threaded connection and/or fasteners. 
     Each stripper may include a gland or retainer and a seal. Each stripper seal may be directional and oriented to seal against drill pipe  10   p  in response to higher pressure in the riser  25  than the UMRP  20 . Each stripper may have a conical shape for fluid pressure to act against a respective tapered surface thereof, thereby generating sealing pressure against the drill pipe  10   p . Each stripper may have an inner diameter slightly less than a pipe diameter of the drill pipe  10   p  to form an interference fit therebetween. Each stripper may be flexible enough to accommodate and seal against threaded couplings of the drill pipe  10   p  having a larger tool joint diameter. The drill pipe  10   p  may be received through a bore of the bearing assembly so that the strippers may engage the drill pipe. The stripper seals may provide a desired barrier in the riser  25  either when the drill pipe  10   p  is stationary or rotating. Once deployed, the RCD  63  may be submerged adjacent the waterline  2   s . The RCD interface may be in fluid communication with a hydraulic power unit (HPU)  32   h  ( FIG. 3A ) and a programmable logic controller (PLC)  35  via an RCD umbilical  19 . 
     Alternatively, an active seal RCD may be used. Alternatively, the RCD  63  may be located above the waterline  2   s  and/or along the UMRP  20  at any other location besides a lower end thereof. Alternatively, the RCD  63  may be assembled as part of the riser  25  at any location therealong or as part of the PCA  1   p . If assembled as part of the PCA  1   p , the RCD return line  29  may extend along the riser  25  as one of the auxiliary lines. 
       FIG. 5  illustrates an alternative RCD housing  70  for use with the drilling system, according to another embodiment of the invention. Returning to  FIG. 1B , the flanged connection between the latch section  62  and the port  63  section may have a lesser outer diameter than the flanged connections between the spools and the respective latch and port sections. The spools  61 ,  64  have been omitted from the alternative RCD housing  70 . Instead, the alternative RCD housing  70  has an extended latch section  72  with the riser flange  65   f  welded to an upper end thereof and a lower end of the port section  73  has the riser flange  65   m  welded thereto, thereby eliminating the larger flanged connections and reducing a required drift diameter of the rotary table  37  needed to pass the RCD housing  70  since an outward flare of the jumpers may be reduced. Alternatively, larger diameter jumpers may be accommodated. 
       FIG. 6  illustrates an alternative RCD housing  80  for use with the drilling system, according to another embodiment of the invention. The alternative RCD housing  80  has a latch section  82  with a nipple  82   n  formed at an upper end thereof and an upper spool  81  welded to to the nipple. The alternative RCD housing  80  also has a port section  83  with a nipple  83   n  formed at a lower end thereof and a lower spool  84  welded to to the nipple, thereby eliminating the larger flanged connections and reducing an a required drift diameter of the rotary table  37  needed to pass the RCD housing  80  since an outward flare of the jumpers may be reduced. Alternatively, larger diameter jumpers may be accommodated. 
     Alternatively, it is contemplated that the connectors  100   f ,  60   m  may be integrally formed with the spools  500   s ,  560 , or may coupled thereto via threaded connection. 
     Embodiments described herein provide RCD systems having diameters sufficiently small enough to fit through an opening of a rotary table while the RCD system is in an assembled configuration. In one example, the an RCD system may include a housing having flanges with a maximum diameter of 45 inches, and external piping having a maximum diameter of about 6.5 inches each. In an RCD system having two external pipes located about 180 degrees from one another, the total width of the RCD system would be about 58 inches. Thus, the RCD system can be disposed through a rotary table opening of about 59-60 inches, while having sufficient clearance and accounting for drift. The reduced dimensions of the RCD system are facilitated by flanged connections that allow fluid channels to pass therethrough, rather than around, at locations coupling the RCD system to risers (e.g., riser joints). 
     While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.