Abstract:
A method of drilling a subsea wellbore includes drilling the subsea wellbore and, while drilling the subsea wellbore: measuring a flow rate of the drilling fluid injected into a tubular string; measuring a flow rate of returns; comparing the returns flow rate to the drilling fluid flow rate to detect a kick by a formation being drilled; and exerting backpressure on the returns using a first variable choke valve. The method further includes, in response to detecting the kick: closing a blowout preventer of a subsea pressure control assembly (PCA) against the tubular string; and diverting the flow of returns from the PCA, through a choke line having a second variable choke valve, and through the first variable choke valve.

Description:
BACKGROUND OF THE DISCLOSURE 
       [0001]    1. Field of the Disclosure 
         [0002]    The present disclosure generally relates to a managed pressure drilling system having a well control mode. 
         [0003]    2. Description of the Related Art 
         [0004]    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. 
         [0005]    Deep water off-shore 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 DISCLOSURE 
       [0006]    The present disclosure generally relates to a managed pressure drilling system having a well control mode. In one embodiment, a method of drilling a subsea wellbore includes drilling the subsea wellbore by: injecting drilling fluid through a tubular string extending into the wellbore from an offshore drilling unit (ODU); and rotating a drill bit disposed on a bottom of the tubular string. The drilling fluid exits the drill bit and carries cuttings from the drill bit. The drilling fluid and cuttings (returns) flow to a subsea wellhead via an annulus defined by an outer surface of the tubular string and an inner surface of the subsea wellbore. The returns flow from the subsea wellhead to the ODU via a marine riser. The method further includes, while drilling the subsea wellbore: measuring a flow rate of the drilling fluid injected into the tubular string; measuring a flow rate of the returns; comparing the returns flow rate to the drilling fluid flow rate to detect a kick by a formation being drilled; and exerting backpressure on the returns using a first variable choke valve. The method further includes, in response to detecting the kick: closing a blowout preventer of a subsea pressure control assembly (PCA) against the tubular string; and diverting the flow of returns from the PCA, through a choke line having a second variable choke valve, and through the first variable choke valve. 
         [0007]    In another embodiment, a managed pressure drilling system includes: a first rotating control device (RCD) for connection to a marine riser; a first variable choke valve for connection to an outlet of the first RCD; a first mass flow meter for connection to an outlet of the first variable choke valve; a splice for connecting an inlet of the first variable choke valve to an outlet of a second variable choke valve; and a programmable logic controller (PLC) in communication with the first variable choke valve and the first mass flow meter. The PLC is configured to perform an operation, including, during drilling of a subsea wellbore: measuring a flow rate of returns using the first mass flow meter; comparing the returns flow rate to a drilling fluid flow rate to detect a kick by a formation being drilled; and exerting backpressure on the returns using the first variable choke valve. The operation further includes, in response to detecting the kick, diverting the returns through the second variable choke valve, the splice, and the first variable choke valve to alleviate pressure on the first variable choke valve. 
         [0008]    In another embodiment, a method of drilling a subsea wellbore includes: drilling the subsea wellbore; and, while drilling the subsea wellbore: measuring a flow rate of drilling fluid injected into a tubular string having a drill bit; measuring a flow rate of drilling returns using a subsea mass flow meter; and comparing the returns flow rate to the drilling fluid flow rate to detect a kick by a formation being drilled. The method further includes, in response to detecting the kick: closing a blowout preventer of a subsea pressure control assembly (PCA) against the tubular string; and diverting the flow of returns from the PCA, through a choke line having a second variable choke valve, and through a first variable choke valve. 
         [0009]    In another embodiment, a managed pressure drilling system includes: a first rotating control device (RCD) for connection to a marine riser; a first variable choke valve for connection to an outlet of the first RCD; a first mass flow meter for connection to an outlet of the first variable choke valve; a splice for connecting an inlet of the first variable choke valve to an outlet of a second variable choke valve; a second RCD for assembly as part of a subsea pressure control assembly; a subsea mass flow meter for connection to an outlet of the second RCD; and a programmable logic controller (PLC) in communication with the first variable choke valve and the first and second mass flow meters. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0010]    So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, 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 disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments. 
           [0011]      FIGS. 1A-1C  illustrate an offshore drilling system in a managed pressure drilling mode, according to one embodiment of the present disclosure. 
           [0012]      FIGS. 2A and 2B  illustrate the offshore drilling system in a managed pressure riser degassing mode.  FIG. 2C  is a table illustrating switching between the modes. 
           [0013]      FIGS. 3A and 3B  illustrate the offshore drilling system in a managed pressure well control mode.  FIG. 3C  illustrates operation of the PLC in the managed pressure well control mode. 
           [0014]      FIGS. 4A and 4B  illustrate the offshore drilling system in an emergency well control mode. 
           [0015]      FIG. 5  illustrates a pressure control assembly (PCA) of a second offshore drilling system in a managed pressure drilling mode, according to another embodiment of the present disclosure. 
       
    
    
     DETAILED DESCRIPTION 
       [0016]      FIGS. 1A-1C  illustrate an offshore drilling system  1  in a managed pressure drilling mode, according to one embodiment of the present disclosure. The drilling system  1  may include a MODU  1   m,  such as a semi-submersible, a drilling rig  1   r,  a fluid handling system  1   h,  a fluid transport system  1   t,  and pressure control assembly (PCA)  1   p,  and a drill string  10 . 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 drilling operations are conducted. The semi-submersible 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 . 
         [0017]    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.  Alternatively, the wellbore may be subsea having a wellhead located adjacent to the waterline and the drilling rig may be a located on a platform adjacent the wellhead. Alternatively, the wellbore may be subterranean and the drilling rig located on a terrestrial pad. 
         [0018]    The drilling rig  1   r  may include a derrick  3 , a floor  4 , a top drive  5 , and a hoist. The top drive  5  may include a motor for rotating  16  a drill string  10 . The top drive motor may be electric or hydraulic. A frame of the top drive  5  may be linked to a rail (not shown) of the derrick  3  for preventing rotation thereof during rotation  16  of the drill string  10  and allowing for vertical movement of the top drive with a traveling block  6  of the hoist. The frame of the top drive  5  may be suspended from the derrick  3  by the traveling block  6 . A Kelly valve  11  may be connected to a quill of a top drive  5 . The quill may be torsionally driven by the top drive motor and supported from the frame by bearings. The top drive  5  may further have an inlet connected to the frame and in fluid communication with the quill. 
         [0019]    The traveling block  6  may be supported by wire rope  7  connected at its upper end 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 . The drilling rig  1  r may further include a drill string compensator (not shown) to account for heave of the MODU  1  m. The drill string compensator may be disposed between the traveling block  6  and the top drive  5  (aka hook mounted) or between the crown block  8  and the derrick  3  (aka top mounted). 
         [0020]    An upper end of the drill string  10  may be connected to the Kelly valve  11 , such as by threaded couplings. 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 threaded couplings, and include a drill bit  15  and one or more drill collars  12  connected thereto, such as by threaded couplings. The drill bit  15  may be rotated  16  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. 
         [0021]    The fluid transport system  1   t  may include an upper marine riser package (UMRP)  20 , a marine riser  25 , a booster line  27 , a choke line  28 , and a return line  29 . The UMRP  20  may include a diverter  21 , a flex joint  22 , a slip (aka telescopic) joint  23 , a tensioner  24 , and a rotating control device (RCD)  26 . A lower end of the RCD  26  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  26 , 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 (not shown). 
         [0022]    The flex joint  22  may also connect to the diverter  21 , such as by a flanged connection. The diverter  21  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 riser  25  may extend from the PCA  1   p  to the MODU  1   m  and may connect to the MODU via the UMRP  20 . The riser  25  may have one or more buoyancy modules (not shown) disposed therealong to reduce load on the tensioner  24 . 
         [0023]    The RCD  26  may include a docking station and a bearing assembly. The docking station may be submerged adjacent the waterline  2   s.  The docking station may include a housing, a latch, and an interface. The RCD housing may be tubular and have one or more sections connected together, such as by flanged connections. The RCD housing may have one or more fluid ports formed through a lower housing section and the docking station may include a connection, such as a flanged outlet, fastened to one of the ports. 
         [0024]    The latch may include a hydraulic actuator, such as a piston, one or more fasteners, such as dogs, and a body. The latch body may be connected to the housing, such as by threaded couplings. A piston chamber may be formed between the latch body and a mid housing section. The latch body may have openings formed through a wall thereof for receiving the respective dogs. The latch piston  63   p  may be disposed in the chamber and may carry seals isolating an upper portion of the chamber from a lower portion of the chamber. A cam surface may be formed on an inner surface of the piston for radially displacing the dogs. The latch body may further have a landing shoulder formed in an inner surface thereof for receiving a protective sleeve or the bearing assembly. 
         [0025]    Hydraulic passages may be formed through the mid housing section and may provide fluid communication between the interface and respective portions of the hydraulic chamber for selective operation of the piston. An RCD umbilical may have hydraulic conduits and may provide fluid communication between the RCD interface and a hydraulic power unit (HPU) via hydraulic manifold. The RCD umbilical may further have an electric cable for providing data communication between a control console and the RCD interface via a controller. 
         [0026]    The bearing assembly may include a catch sleeve, one or more strippers, and a bearing pack. 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 seal 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 seal 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 seal 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 stripper seals may engage the drill pipe  10   p.  The stripper seals may provide a desired barrier in the riser  25  either when the drill pipe  10   p  is stationary or rotating. 
         [0027]    The catch sleeve may have a landing shoulder formed at an outer surface thereof, a catch profile formed in an outer surface thereof, and may carry one or more seals on an outer surface thereof. Engagement of the latch dogs with the catch sleeve may connect the bearing assembly to the docking station. The gland may have a landing shoulder formed in an inner surface thereof and a catch profile formed in an inner surface thereof for retrieval by a bearing assembly running tool. The bearing pack may support the strippers from the catch sleeve such that the strippers may rotate relative to the docking station. 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 threaded couplings and/or fasteners. 
         [0028]    Alternatively, the bearing assembly may be non-releasably connected to the housing. Alternatively, the RCD may be located above the waterline and/or along the UMRP at any other location besides a lower end thereof. Alternatively, the RCD may be assembled as part of the riser at any location therealong or as part of the PCA. Alternatively, an active seal RCD may be used instead. 
         [0029]    The PCA  1   p  may be connected to a wellhead  50  adjacently located 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 couplings. Once the conductor string  51  has been set, a subsea wellbore  100  may be drilled into the seafloor  2   f  and a casing string  52  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 couplings. The wellhead housing may land in the conductor housing during deployment of the casing string  52 . The casing string  52  may be cemented  101  into the wellbore  100 . The casing string  52  may extend to a depth adjacent a bottom of an upper formation  104   u.  The upper formation  104   u  may be non-productive and a lower formation  104   b  may be a hydrocarbon-bearing reservoir. 
         [0030]    Alternatively, the lower formation  104   b  may be non-productive (e.g., a depleted zone), environmentally sensitive, such as an aquifer, or unstable. Although shown as vertical, the wellbore  100  may include a vertical portion and a deviated, such as horizontal, portion. 
         [0031]    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  76 , 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 . 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.    
         [0032]    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  76  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. 
         [0033]    The LMRP may receive a lower end of the riser  25  and connect the riser to the PCA  1   p.  The control pod  76  may be in electric, hydraulic, and/or optical communication with a programmable logic controller (PLC)  75  and/or a rig controller (not shown) onboard the MODU  1   m  via an umbilical  70 . The control pod  76  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  70 . The umbilical  70  may include one or more hydraulic and/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 PLC  75  and/or rig controller may operate the PCA  1  p via the umbilical  70  and the control pod  76 . 
         [0034]    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  27  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, a separate kill line (not shown) 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  30   b.  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. 
         [0035]    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  76 . The lines  27 ,  28  and umbilical  70  may extend between the MODU  1   m  and the PCA  1   p  by being fastened to brackets disposed along the riser  25 . Each line  27 ,  28  may be a flow conduit, such as coiled tubing. Each shutoff valve  45   a - e  may be automated and have a hydraulic actuator (not shown) operable by the control pod  76 . 
         [0036]    Alternatively, the umbilical may be extended between the MODU and the PCA independently of the riser. Alternatively, the valve actuators may be electrical or pneumatic. 
         [0037]    The fluid handling system  1   h  may include one or pumps  30   b,d,  a gas detector  31 , a reservoir for drilling fluid  60   d,  such as a tank, a fluid separator, such as a mud-gas separator (MGS)  32 , a solids separator, such as a shale shaker  33 , one or more flow meters  34   b,d,r,  one or more pressure sensors  35   c,d,r,  and one or more variable choke valves, such as a managed pressure (MP) choke  36   a  and a well control (WC) choke  36   m.  The mud-gas separator  32  may be vertical, horizontal, or centrifugal and may be operable to separate gas from returns  60   r.  The separated gas may be stored or flared. 
         [0038]    A lower end of the return line  29  may be connected to an outlet of the RCD  26  and an upper end of the return line may be connected to an inlet stem of a first flow tee  39   a  and have a first shutoff valve  38   a  assembled as part thereof. An upper end of the choke line  28  may be connected an inlet stem of a second flow tee  39   b  and have the WC choke  36   m  and pressure sensor  35   c  assembled as part thereof. A first spool may connect an outlet stem of the first tee  39   a  and an inlet stem of a third tee  39   c  ( FIG. 2A ). The pressure sensor  35   r,  MP choke  36   a,  flow meter  34   r,  gas detector  31 , and a fourth shutoff valve  38   d  may be assembled as part of the first spool. A second spool may connect an outlet stem of the third tee  39   c  and an inlet of the MGS  32  and have a sixth shutoff valve  38   f  assembled as part thereof. 
         [0039]    A third spool may connect an outlet stem of the second tee  39   b  and an inlet stem of a fourth tee  39   d  ( FIG. 2A ) and have a third shutoff valve  38   c  assembled as part thereof. A first splice may connect branches of the first  39   a  and second  39   b  tees and have a second shutoff valve  38   b  assembled as part thereof. A second splice may connect branches of the third  39   c  and fourth  39   d  tees and have a fifth shutoff valve  38   e  assembled as part thereof. A fourth spool may connect an outlet stem of the fourth tee  39   d  and an inlet stem of the fifth tee  39   e  and have a seventh shutoff valve  38   g  assembled as part thereof. A third splice may connect a liquid outlet of the MGS  32  and a branch of the fifth tee  39   e  and have an eighth shutoff valve  38   h  assembled as part thereof. An outlet stem of the fifth tee  39   e  may be connected to an inlet of the shale shaker  33 . 
         [0040]    A supply line  37   p,h  may connect an outlet of the mud pump  30   d  to the top drive inlet and may have the flow meter  34   d  and the pressure sensor  35   d  assembled as part thereof. An upper end of the booster line  27  may have the flow meter  34   b  assembled as part thereof. Each pressure sensor  35   c,d,r  may be in data communication with the PLC  75 . The pressure sensor  35   r  may be operable to monitor backpressure exerted by the MP choke  36   a.  The pressure sensor  35   c  may be operable to monitor backpressure exerted by the WC choke  36   m.  The pressure sensor  35   d  may be operable to monitor standpipe pressure. Each choke  36   a,m  may be fortified to operate in an environment where drilling returns  60   r  may include solids, such as cuttings. The MP choke  36   a  may include a hydraulic actuator operated by the PLC  75  via the HPU to maintain backpressure in the riser  25 . The WC choke  36   m  may be manually operated. 
         [0041]    Alternatively, the choke actuator may be electrical or pneumatic. Alternatively, the WC choke  36   m  may also include an actuator operated by the PLC  75 . 
         [0042]    The flow meter  34   r  may be a mass flow meter, such as a Coriolis flow meter, and may be in data communication with the PLC  75 . The flow meter  34   r  may be connected in the first spool downstream of the MP choke  36   a  and may be operable to monitor a flow rate of the drilling returns  60   r.  Each of the flow meters  34   b,d  may be a volumetric flow meter, such as a Venturi flow meter, and may be in data communication with the PLC  75 . The flow meter  34   d  may be operable to monitor a flow rate of the mud pump  30   d.  The flow meter  34   b  may be operable to monitor a flow rate of the drilling fluid  60   d  pumped into the riser  25  ( FIG. 2B ). The PLC  75  may receive a density measurement of drilling fluid  60   d  from a mud blender (not shown) to determine a mass flow rate of the drilling fluid  60   d  from the volumetric measurement of the flow meters  34   b,d.    
         [0043]    Alternatively, a stroke counter (not shown) may be used to monitor a flow rate of the mud pump and/or booster pump instead of the volumetric flow meters. Alternatively, either or both of the volumetric flow meters may be mass flow meters. 
         [0044]    The gas detector  31  may be operable to extract a gas sample from the returns  60   r  (if contaminated by formation fluid  62  ( FIG. 3C )) and analyze the captured sample to detect hydrocarbons, such as saturated and/or unsaturated C1 to C10 and/or aromatic hydrocarbons, such as benzene, toluene, ethyl benzene and/or xylene, and/or non-hydrocarbon gases, such as carbon dioxide and nitrogen. The gas detector  31  may include a body, a probe, a chromatograph, and a carrier/purge system. The body may include a fitting and a penetrator. The fitting may have end connectors, such as flanges, for connection within the first spool and a lateral connector, such as a flange for receiving the penetrator. The penetrator may have a blind flange portion for connection to the lateral connector, an insertion tube extending from an external face of the blind flange portion for receiving the probe, and a dip tube extending from an internal face thereof for receiving one or more sensors, such as a pressure and/or temperature sensor. 
         [0045]    The probe may include a cage, a mandrel, and one or more sheets. Each sheet may include a semi-permeable membrane sheathed by inner and outer protective layers of mesh. The mandrel may have a stem portion for receiving the sheets and a fitting portion for connection to the insertion tube. Each sheet may be disposed on opposing faces of the mandrel and clamped thereon by first and second members of the cage. Fasteners may then be inserted into respective receiving holes formed through the cage, mandrel, and sheets to secure the probe components together. The mandrel may have inlet and outlet ports formed in the fitting portion and in communication with respective channels formed between the mandrel and the sheets. The carrier/purge system may be connected to the mandrel ports and a carrier gas, such as helium, argon, or nitrogen, may be injected into the mandrel inlet port to displace sample gas trapped in the channels by the membranes to the mandrel outlet port. The carrier/purge system may then transport the sample gas to the chromatograph for analysis. The carrier purge system may also be routinely run to purge the probe of condensate. The chromatograph may be in data communication with the PLC to report the analysis of the sample. The chromatograph may be configured to only analyze the sample for specific hydrocarbons to minimize sample analysis time. For example, the chromatograph may be configured to analyze only for C1-C5 hydrocarbons in twenty-five seconds. 
         [0046]    In the drilling mode, the mud pump  30   d  may pump drilling fluid  60   d  from the drilling fluid tank, through the standpipe  37   p  and Kelly hose  37   h  to the top drive  5 . The drilling fluid  60   d  may include a base liquid. The base liquid may be base refined or synthetic oil, water, brine, or a water/oil emulsion. The drilling fluid  60   d  may further include solids dissolved or suspended in the base liquid, such as organophilic clay, lignite, and/or asphalt, thereby forming a mud. 
         [0047]    The drilling fluid  60   d  may flow from the Kelly hose  37   h  and into the drill string  10  via the top drive  5 . The drilling fluid  60   d  may flow down through the drill string  10  and exit the drill bit  15 , where the fluid may circulate the cuttings away from the bit and return the cuttings up an annulus  105  formed between an inner surface of the casing  101  or wellbore  100  and an outer surface of the drill string  10 . The returns  60   r  (drilling fluid  60   d  plus cuttings) may flow through the annulus  105  to the wellhead  50 . The returns  60   r  may continue from the wellhead  50  and into the riser  25  via the PCA  1   p.  The returns  60   r  may flow up the riser  25  to the RCD  26 . The returns  60   r  may be diverted by the RCD  26  into the return line  29  via the RCD outlet. The returns  60   r  may continue from the return line  29 , through the open (depicted by phantom) first shutoff valve  38   a  and first tee  39   a,  and into the first spool. The returns  60   r  may flow through the MP choke  36   a,  the flow meter  34   r,  the gas detector  31 , and the open fourth shutoff valve  38   d  to the third tee  39   c.  The returns  60   r  may continue through the second splice and to the fourth tee  39   d  via the open fifth shutoff valve  38   e.  The returns  60   r  may continue through the third spool to the fifth tee  39   e  via the open seventh shutoff valve  38   g.  The returns  60   r  may then flow into the shale shaker  33  and be processed thereby to remove the cuttings, thereby completing a cycle. As the drilling fluid  60   d  and returns  60   r  circulate, the drill string  10  may be rotated  16  by the top drive  5  and lowered by the traveling block  6 , thereby extending the wellbore  100  into the lower formation  104   b.    
         [0048]    Alternatively, the sixth  38   f  and eighth  38   h  shutoff valves may be open and the fifth  38   e  and seventh  38   g  shutoff valves may be closed in the drilling mode, thereby routing the returns  60   r  through the MGS  32  before discharge into the shaker  33 . 
         [0049]    The PLC  75  may be programmed to operate the MP choke  36   a  so that a target bottomhole pressure (BHP) is maintained in the annulus  105  during the drilling operation. The target BHP may be selected to be within a drilling window defined as greater than or equal to a minimum threshold pressure, such as pore pressure, of the lower formation  104   b  and less than or equal to a maximum threshold pressure, such as fracture pressure, of the lower formation, such as an average of the pore and fracture BHPs. 
         [0050]    Alternatively, the minimum threshold may be stability pressure and/or the maximum threshold may be leakoff pressure. Alternatively, threshold pressure gradients may be used instead of pressures and the gradients may be at other depths along the lower formation  130   b  besides bottomhole, such as the depth of the maximum pore gradient and the depth of the minimum fracture gradient. Alternatively, the PLC  75  may be free to vary the BHP within the window during the drilling operation. 
         [0051]    A static density of the drilling fluid  60   d  (typically assumed equal to returns  60   r;  effect of cuttings typically assumed to be negligible) may correspond to a threshold pressure gradient of the lower formation  104   b,  such as being equal to a pore pressure gradient. During the drilling operation, the PLC  75  may execute a real time simulation of the drilling operation in order to predict the actual BHP from measured data, such as standpipe pressure from sensor  35   d,  mud pump flow rate from flow meter  34   d,  wellhead pressure from any of the sensors  47   a - c,  and return fluid flow rate from flow meter  34   r.  The PLC  75  may then compare the predicted BHP to the target BHP and adjust the MP choke  36   a  accordingly. 
         [0052]    Alternatively, a static density of the drilling fluid  60   d  may be slightly less than the pore pressure gradient such that an equivalent circulation density (ECD) (static density plus dynamic friction drag) during drilling is equal to the pore pressure gradient. Alternatively, a static density of the drilling fluid  60   d  may be slightly greater than the pore pressure gradient. 
         [0053]    During the drilling operation, the PLC  75  may also perform a mass balance to monitor for a kick ( FIG. 3C ) or lost circulation (not shown). As the drilling fluid  60   d  is being pumped into the wellbore  100  by the mud pump  30   d  and the returns  60   r  are being received from the return line  29 , the PLC  75  may compare the mass flow rates (i.e., drilling fluid flow rate minus returns flow rate) using the respective counters/meters  34 d,r. The PLC  75  may use the mass balance to monitor for formation fluid  62  entering the annulus  105  and contaminating  61   r  the returns  60   r  or returns  60   r  entering the formation  104   b.  Upon detection of either event, the PLC  75  may shift the drilling system  1  into a managed pressure riser degassing mode. The gas detector  31  may also capture and analyze samples of the returns  60   r  as an additional safeguard for kick detection. 
         [0054]    Alternatively, the PLC  75  may estimate a mass rate of cuttings (and add the cuttings mass rate to the intake sum) using a rate of penetration (ROP) of the drill bit or a mass flow meter may be added to the cuttings chute of the shaker and the PLC may directly measure the cuttings mass rate. Alternatively, the gas detector  31  may be bypassed during the drilling operation. Alternatively, the booster pump  30   b  may be operated during drilling to compensate for any size discrepancy between the riser annulus and the casing/wellbore annulus and the PLC may account for boosting in the BHP control and mass balance using the flow meter  34 b. 
         [0055]      FIGS. 2A and 2B  illustrate the offshore drilling system  1  in a managed pressure riser degassing mode.  FIG. 2C  is a table illustrating switching between the modes. To shift the drilling system  1  to degassing mode, the PLC  75  may halt injection of the drilling fluid  60   d  by the mud pump  30   d  and halt rotation  16  of the drill string  10  by the top drive  5 . The Kelly valve  11  may be closed. The top drive  5  may also be raised to remove weight on the bit  15 . The PLC  75  may then close one or more of the BOPs, such as annular BOP  42   a  and pipe ram BOP  42   u,  against an outer surface of the drill pipe  10   p.  The PLC  75  may close the fifth  38   e  and seventh  38   g  shutoff valves and open the sixth  38   f  and eighth  38   h  shutoff valves. The PLC  75  may then open the first booster line shutoff valve  45   a  and operate the booster pump  30   b,  thereby pumping drilling fluid  60   d  into a top of the booster line  27 . The drilling fluid  60   d  may flow down the booster line  27  and into the upper flow cross  41   u  via the open shutoff valve  45   a.    
         [0056]    The drilling fluid  60   d  may flow through the LMRP and into a lower end of the riser  25 , thereby displacing any contaminated returns  61  r present therein. The drilling fluid  60   d  may flow up the riser  25  and drive the contaminated returns  61  r out of the riser  25 . The contaminated returns  61   r  may be driven up the riser  25  to the RCD  26 . The contaminated returns  61   r  may be diverted by the RCD  26  into the return line  29  via the RCD outlet. The contaminated returns  61   r  may continue from the return line  29 , through the open first shutoff valve  38   a  and first tee  39   a,  and into the first spool. The contaminated returns  61  r may flow through the MP choke  36   a,  the flow meter  34   r,  the gas detector  31 , and the open fourth shutoff valve  38   d  to the third tee  39   c.  The contaminated returns  61  r may continue into an inlet of the MGS  32  via the open sixth shutoff valve  38   f.  The MGS  32  may degas the contaminated returns  61   r  and a liquid portion thereof may be discharged into the third splice. The liquid portion of the contaminated returns  61  r may continue into the shale shaker  33  via the open eighth shutoff valve  38   h  and the fifth tee  39   e.  The shale shaker  33  may process the contaminated liquid portion to remove the cuttings and the processed contaminated liquid portion may be diverted into a disposal tank (not shown). 
         [0057]    As the riser  25  is being flushed, the gas detector  31  may capture and analyze samples of the contaminated returns  61  r to ensure that the riser  25  has been completely degassed. Once the riser  25  has been degassed, the PLC  75  may shift the drilling system  1  into managed pressure well control mode. If the event that triggered the shift was lost circulation, the returns  60   r  may or may not have been contaminated by fluid from the lower formation  104   b.    
         [0058]    Alternatively, if the booster pump  30   b  had been operating in drilling mode to compensate for any size discrepancy, then the booster pump  30   b  may or may not remain operating during shifting between drilling mode and riser degassing mode. 
         [0059]      FIGS. 3A and 3B  illustrate the offshore drilling system  1  in a managed pressure well control mode. To shift the drilling system  1  to the managed pressure well control mode, the PLC  75  may halt injection of the drilling fluid  60   d  by the booster pump  30   b  and close the booster line shutoff valve  45   a.  The Kelly valve  11  may be opened. The PLC  75  may close the first shutoff valve  38   a  and open the second shutoff valve  38   b.  The PLC  75  may then open the second choke line shutoff valve  45   e  and operate the mud pump  30   d,  thereby pumping drilling fluid  60   d  into a top of the drill string  10  via the top drive  5 . The drilling fluid  60   d  may be flow down through the drill string  10  and exit the drill bit  15 , thereby displacing the contaminated returns  61   r  present in the annulus  105 . The contaminated returns  61   r  may be driven through the annulus  105  to the wellhead  50 . The contaminated returns  61   r  may be diverted into the choke line  28  by the closed BOPs  41   a,u  and via the open shutoff valve  45   e.  The contaminated returns  61   r  may be driven up the choke line  28  to the WC choke  36   m.  The WC choke  36   m  may be fully relaxed or be bypassed. 
         [0060]    The contaminated returns  61   r  may continue through the WC choke  36   m  and into the first branch via the second tee  39   b.  The contaminated returns  61   r  may flow into the first spool via the open second shutoff valve  38   b  and first tee  39   a.  The contaminated returns  61   r  may flow through the MP choke  36   a,  the flow meter  34   r,  the gas detector  31 , and the open fourth shutoff valve  38   d  to the third tee  39   c.  The contaminated returns  61   r  may continue into the inlet of the MGS  32  via the open sixth shutoff valve  38   f.  The MGS  32  may degas the contaminated returns  61  r and a liquid portion thereof may be discharged into the third splice. The liquid portion of the contaminated returns  61   r  may continue into the shale shaker  33  via the open eighth shutoff valve  38   h  and the fifth tee  39   e.  The shale shaker  33  may process the contaminated liquid portion to remove the cuttings and the processed contaminated liquid portion may be diverted into a disposal tank (not shown). 
         [0061]      FIG. 3C  illustrates operation of the PLC  75  in the managed pressure well control mode. A flow rate of the mud pump  30   d  for managed pressure well control may be reduced relative to the flow rate of the mud pump during the drilling mode to account for the reduced flow area of the choke line  28  relative to the flow area of the a riser annulus formed between the riser  25  and the drill string  10 . If the trigger event was a kick, as the drilling fluid  60   d  is being pumped through the drill string  10 , annulus  105 , and choke line  28 , the gas detector  31  may capture and analyze samples of the contaminated returns  61  r and the flow meter  34   r  may be monitored so the PLC  75  may determine a pore pressure of the lower formation  104   b.  If the trigger event was lost circulation (not shown), the PLC  75  may determine a fracture pressure of the formation. The pore/fracture pressure may be determined in an incremental fashion, i.e. for a kick, the MP choke  36   a  may be monotonically or gradually tightened  63   a,b  until the returns are no longer contaminated with production fluid  62 . Once the back pressure that ended the influx of formation is known, the PLC  75  may calculate the pore pressure to control the kick. The inverse of the incremental process may be used to determine the fracture pressure for a lost circulation scenario. 
         [0062]    Once the PLC  75  has determined the pore pressure, the PLC may calculate a pore pressure gradient and a density of the drilling fluid  60   d  may be increased to correspond to the determined pore pressure gradient. The increased density drilling fluid may be pumped into the drill string  10  until the annulus  105  and choke line  28  are full of the heavier drilling fluid. The riser  25  may then be filled with the heavier drilling fluid. The PLC  75  may then shift the drilling system  1  back to drilling mode and drilling of the wellbore  100  through the lower formation  104   b  may continue with the heavier drilling fluid such that the returns  64   r  therefrom maintain at least a balanced condition in the annulus  105 . 
         [0063]    Should the kick be severe such that the back pressure exerted by the MP choke  36   a  approaches a maximum operating pressure of the first spool, the WC choke  36   m  may be tightened (or brought online if bypassed) to alleviate pressure from the MP choke  36   a  until the kick has been controlled. Since the WC choke  36   m  is located upstream of the first spool, the chokes  36   a,m  may operate in a serial fashion. The WC choke  36   m  may function as a high pressure stage and the MP choke  36   a  may function as a low pressure stage, thereby effectively increasing a maximum operating pressure of the first spool. Should tightening the chokes  36   a,m  fail to control the kick, the PLC  75  may shift the drilling system into emergency well control mode. 
         [0064]      FIGS. 4A and 4B  illustrate the offshore drilling system  1  in an emergency well control mode. To shift the drilling system  1  to the emergency well control mode, the PLC  75  may halt injection of the drilling fluid  60   d  by the mud pump  30   b  and close the second  38   b  and fourth  38   d  shutoff valves and open the fifth shutoff valve  38   e.  The PLC  75  may close a supply valve (not shown) for the mud pump  30   d  from the drilling fluid tank and open a supply valve (not shown) for the mud pump  30   d  from a kill fluid tank (not shown). The PLC  75  may then operate the mud pump  30   d,  thereby pumping kill fluid  65  into a top of the drill string  10  via the top drive  5 . The kill fluid  65  may be flow down through the drill string  10  and exit the drill bit  15 , thereby displacing the contaminated drilling fluid present in the annulus  105 . The contaminated drilling fluid may be driven through the annulus  105  to the wellhead  50 . The contaminated drilling fluid may be diverted into the choke line  28  by the closed BOPs  41   a,u  and via the open shutoff valve  45 . The contaminated drilling fluid may be driven up the choke line  28  to the WC choke  36   m.    
         [0065]    The contaminated drilling fluid may continue through the WC choke  36   m  and into the second spool via the second tee  39   b.  The contaminated drilling fluid may flow into the second branch via the open third shutoff valve  38   c  and fourth tee  39   d.  The contaminated drilling fluid may bypass the first spool and continue into the inlet of the MGS  32  via the open fifth  38   e  and  38   f  sixth shutoff valves. The MGS  32  may degas the contaminated drilling fluid and a liquid portion thereof may be discharged into the third splice. The liquid portion of the contaminated drilling fluid may continue into the shale shaker  33  via the open eighth shutoff valve  38   h  and the fifth tee  39   e.  The processed contaminated liquid portion may be diverted into a disposal tank (not shown). The WC choke  36   m  may be operated to bring the kick under control. 
         [0066]      FIG. 5  illustrates a pressure control assembly (PCA) of a second offshore drilling system in a managed pressure drilling mode, according to another embodiment of the present disclosure. The second drilling system may include the MODU  1   m,  the drilling rig  1   r,  the fluid handling system  1   h,  the fluid transport system  1   t,  and a pressure control assembly (PCA)  201   p.  The PCA  201   p  may include the wellhead adapter  40   b,  the one or more flow crosses  41   u,m,b,  the blow out preventers (BOPs)  42   a,u,b,  the LMRP, the accumulators  44 , the receiver  46 , a second RCD  226 , and a subsea flow meter  234 . 
         [0067]    The second RCD  226  may be similar to the first RCD  26 . A lower end of the second RCD housing may be connected to the annular BOP  42   a  and an upper end of the second RCD housing may be connected to the upper flow cross  41   u,  such as by flanged connections. A pressure sensor may be connected to an upper housing section of the second RCD  226 . The pressure sensor may be in data communication with the control pod  76  and the second RCD latch piston may be in fluid communication with the control pod via an interface of the second RCD  226 . 
         [0068]    A lower end of a subsea spool may be connected to an outlet of the second RCD  226  and an upper end of the spool may be connected to the upper flow cross  41   u.  The spool may have first  245   a  and second  245   b  shutoff valves and the subsea flow meter  234  assembled as a part thereof. Each shutoff valve  245   a,b  may be automated and have a hydraulic actuator (not shown) operable by the control pod  76  via fluid communication with a respective umbilical conduit or the LMRP accumulators  44 . The subsea flow meter  234  may be a mass flow meter, such as a Coriolis flow meter, and may be in data communication with the PLC  75  via the pod  76  and the umbilical  70 . 
         [0069]    Alternatively, a subsea volumetric flow meter may be used instead of the mass flow meter. 
         [0070]    In the drilling mode, the returns  60   r  may flow through the annulus  105  to the wellhead  50 . The returns  60   r  may continue from the wellhead  50  to the second RCD  226  via the BOPs  42   a,u,b.  The returns  60   r  may be diverted by the second RCD  226  into the subsea spool via the second RCD outlet. The returns  60   r  may flow through the open second shutoff valve  245   b,  the subsea flow meter  234 , and the first shutoff valve  245   a  to a branch of the upper flow cross  41   u.  The returns  60   r  may flow into the riser  25  via the upper flow cross  41   u,  the receiver  46 , and the LMRP. The returns  60   r  may flow up the riser  25  to the first RCD  26 . The returns  60   r  may be diverted by the first RCD  26  into the return line  29  via the first RCD outlet. The returns  60   r  may continue from the return line  29 , through the open first shutoff valve  38   a  and first tee  39   a,  and into the first spool. The returns  60   r  may flow through the MP choke  36   a,  the flow meter  34   r,  the gas detector  31 , and the open fourth shutoff valve  38   d  to the third tee  39   c.  The returns  60   r  may continue through the second splice and to the fourth tee  39   d  via the open fifth shutoff valve  38   e.  The returns  60   r  may continue through the third spool to the fifth tee  39   e  via the open seventh shutoff valve  38   g.  The returns  60   r  may then flow into the shale shaker  33  and be processed thereby to remove the cuttings, thereby completing a cycle. 
         [0071]    During the drilling operation, the PLC may rely on the subsea flow meter  234  instead of the surface flow meter  34   r  to perform BHP control and the mass balance. The surface flow meter  34   r  may be used as a backup to the subsea flow meter  234  should the subsea flow meter fail. 
         [0072]    The degassing, well control, and emergency modes for the PCA  201  p may be similar to that of the PCA  1   p.    
         [0073]    While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope of the invention is determined by the claims that follow.