Patent Publication Number: US-11661802-B1

Title: Cross BOP swivel joint for string rotation during well control events

Description:
BACKGROUND 
     Field 
     The present disclosure relates to natural resource well drilling and hydrocarbon production from subterranean formations, in particular, to cross BOP swivel joints for rotating drill strings during well control events. 
     Technical Background 
     Extracting hydrocarbons from subterranean sources often includes drilling a wellbore from the surface to the subterranean geological formation containing the hydrocarbons. The wellbore forms a pathway that permits both fluids and apparatus to traverse between the surface and the subterranean geologic formation. Besides defining the void volume of the wellbore, the wellbore wall also acts as the interface through which fluids can flow from the subterranean formations to the interior of the wellbore. Hydrocarbon producing wellbores extend subsurface and intersect various subterranean formations where hydrocarbons are trapped. The wellbore can contain at least a portion of a fluid conduit that links the interior of the wellbore to the surface. The fluid conduit connecting the interior of the wellbore to the surface can permit regulated fluid flow from the interior of the wellbore to the surface and allow for access between equipment on the surface and the interior of the wellbore. 
     Specialized drilling equipment, techniques, and materials are utilized to form the wellbore, complete the wellbore, and extract the hydrocarbons from hydrocarbon-bearing subterranean formations. The wellbore is initially formed by operating a drilling apparatus, which includes a drill bit coupled to the downhole end of a drill string, to bore into the earth to form the wellbore. A drive system at the surface rotates the drill string while drilling fluids are pumped downhole through the drill string. The drilling fluids flow into the wellbore through the drill bit and return to the surface through an annulus defined between the drill string and the wellbore wall. The drilling fluid convey cuttings uphole to the surface and provides hydrostatic pressure in the wellbore that maintains formation fluids in the formation until completion of the wellbore and commencement of hydrocarbon production, among other functions. 
     Imbalances between wellbore fluid pressure and formation pressure can result in fluids from the formation flowing into the wellbore and upwards through the annulus. These pressure imbalances that result in formation fluids flowing into the annulus of the wellbore is sometimes referred to as formation kick. The formation kick is considered a blowout when the formation fluids reach the surface. To control formation kick or respond to a blowout, modern drilling rigs include one or more blowout preventers (BOP), which are mechanical devices that seal the annulus between the wellbore wall and the outer surface of the drill string to prevent formation fluids from reaching the surface or to stop the flow of formation fluids out of the annulus at the surface. In response to formation kick, blowout, or other condition, the BOPs are engaged to shut in the wellbore until the pressure imbalance between the wellbore and the formation can be stabilized. 
     SUMMARY 
     During well control events, the BOPs are engaged to seal the annulus between the drill string and the wellbore wall. Pipe ram BOPs and annular BOPs form a seal between the outer surface of the drill string and the wellbore wall, where the seal prevents the flow of fluids through the annulus back to the surface while allowing the flow of fluids into the wellbore through the drill string. Often, these BOPs engage directly with the outer surface of the drill string. The contact between the BOPs and the outer surface of the drill string and the pressure exerted by the BOPs on the outer surface of the drill string can prevent the drill string from being rotated during the well control event. An ongoing need exists for tools, such as cross BOP swivel joints that can enable rotation of the drill string during well control events. 
     The present disclosure is directed to cross BOP swivel joints that enable rotation of the drill string during well control events, such as when blowout preventers are engaged to shut in the wellbore. The cross BOP swivel joints of the present disclosure include a swivel housing, an internal pipe extending through the swivel housing, journal bearings radially disposed between the swivel housing and the internal pipe, and one or a plurality of central bearings axially disposed between the journal bearings and between the internal pipe and the swivel housing. The journal bearings and central bearings allow the internal pipe to efficiently rotate relative to the swivel housing. Both ends of the internal pipe are coupled to the drill string. The cross BOP swivel joint can enable rotation of the drill string relative to the wellbore during a well control event, during which a pipe-ram BOP, annular BOP, or both are actuated to engage with the swivel housing of the cross BOP swivel joint. The drill string can be rotated through rotation of the internal pipe relative to the swivel housing when the BOPs are engaged with the swivel housing. The central bearings can further provide radial support to the swivel housing to reduce or prevent deflection of the swivel housing radially inward due to the pressure exerted by a pipe ram BOP or annular BOP. Thus, the central bearings can prevent the deflection of the swivel housing from contacting the internal pipe and interfering with rotation of the internal pipe. 
     According to a first aspect of the present disclosure, a cross BOP swivel joint for crossing a blowout preventer (BOP) of a drilling apparatus can include a swivel housing comprising a hollow cylindrical wall having a top end, a bottom end, an inner surface that defines an inner cavity extending axially through the swivel housing, and an outer surface. The cross BOP swivel joint can further include an internal pipe received through the inner cavity of the swivel housing, where the internal pipe can comprise an upper loading shoulder proximate the top end of the swivel housing and a lower loading shoulder proximate the bottom end of the swivel housing. The cross BOP swivel joint can further include an upper journal bearing, a lower journal bearing, and at least one central bearing, each of which may be radially disposed between an outer surface of the internal pipe and the inner surface of the cylindrical wall of the swivel housing. The upper journal bearing may axially disposed between the upper loading shoulder of the internal pipe and the top end of the swivel housing. The lower journal bearing may be axially disposed between the lower loading shoulder of the internal pipe and the bottom end of the swivel housing. The upper journal bearing and the lower journal bearing may allow the internal pipe to rotate relative to the swivel housing. The at least one central bearing may be axially disposed between the upper journal bearing and the lower journal bearing. The outer surface of the swivel housing may contact the blowout preventer when the blowout preventer is engaged with the cross BOP swivel joint. The at least one central bearing may provide radial support to the swivel housing that reduces deformation of the swivel housing radially inward towards the internal pipe when the blowout preventer is engaged with the outer surface of the swivel housing. 
     A second aspect of the present disclosure may include the first aspect comprising a plurality of central bearings spaced apart from each other and distributed axially between the upper journal bearing and the lower journal bearing. 
     A third aspect of the present disclosure may include either one of the first or second aspects, where an axial center of the swivel housing may be a point that is axially disposed halfway between the upper journal bearing and the lower journal bearing. The at least one central bearing may be axially positioned at a distance from the axial center of the swivel housing that is less than 40% of an axial length between the upper journal bearing and the lower journal bearing. 
     A fourth aspect of the present disclosure may include the third aspect, comprising a plurality of central bearings, where each of the plurality of central bearings may be axially positioned at a distance from the axial center of the swivel housing that is less than 40% of the axial length between the upper journal bearing and the lower journal bearing. 
     A fifth aspect of the present disclosure may include the fourth aspect, where the plurality of central bearings may be spaced apart and evenly distributed axially between the upper journal bearing and the lower journal bearing. 
     A sixth aspect of the present disclosure may include any one of the first through fifth aspects, where the at least one central bearing can comprise at least one ball bearing. 
     A seventh aspect of the present disclosure may include the sixth aspect, where the at least one ball bearing may comprises an outer race secured to the inner surface of the swivel housing, an inner race secured to the outer surface of the internal pipe, and a plurality of rigid balls disposed between the inner race and the outer race, where the at least one ball bearing stabilizes rotation of the internal pipe relative to the swivel housing and reduces deformation of the swivel housing radially inward towards the internal pipe when a blowout preventer is engaged with the outer surface of the swivel housing. 
     An eighth aspect of the present disclosure may include any one of the first through seventh aspects, where the upper journal bearing and the lower journal bearing may be rigidly coupled to the swivel housing and slidably engaged with the internal pipe to allow the internal pipe to rotate relative to the journal bearing and swivel housing. 
     A ninth aspect of the present disclosure may include any one of the first through eighth aspects, further comprising a plurality of seals disposed radially between an outer surface of the internal pipe and an inner surface of the cylindrical wall of the swivel housing. The seals may restrict fluid flow through an annular gap between the internal pipe and the inner surface of the cylindrical wall of the swivel housing. 
     A tenth aspect of the present disclosure may include the ninth aspect, where the plurality of seals may comprise a plurality of upper seals disposed axially between the upper journal bearing and the top end of the swivel housing and a plurality of lower seals disposed axially between the lower journal bearing and the bottom end of the swivel housing. 
     An eleventh aspect of the present disclosure may include either one of the ninth or tenth aspects, where the plurality of seals may comprise a plurality of internal seals disposed axially between the at least one central bearing and the upper journal bearing and between the at least one central bearing and the lower journal bearing. 
     A twelfth aspect of the present disclosure may include any one of the ninth through eleventh aspects, where an annular compartment may be defined radially between the inner surface of the swivel housing and the outer surface of the internal pipe, one or more internal seals may be radially disposed in the annular compartment, and the one or more internal seals fluidly may separate the annular compartment into a plurality of annular compartments. 
     A thirteenth aspect of the present disclosure may include the twelfth aspect, further comprising a lubricant disposed in the plurality of annular compartments. 
     A fourteenth aspect of the present disclosure may include either one of the twelfth or thirteenth aspects, further comprising at least one port in the swivel housing, wherein the at least one port may extend radially through the swivel housing and the at least one port may be in fluid communication with an annular compartment. 
     A fifteenth aspect of the present disclosure may include any one of the first through fourteenth aspects, where the internal pipe may extend axially above the top end and below the bottom end of the swivel housing. 
     A sixteenth aspect of the present disclosure may include fifteenth aspect, where the internal pipe may further comprise a box connection at an upper end of the drill pipe and a pin connection at a lower end of the drill pipe. 
     A seventeenth aspect of the present disclosure may include any one of the first through sixteenth aspects and may be directed to a drilling apparatus comprising at least one blowout preventer, the cross BOP swivel joint of any one of the first through sixteenth aspects, and a drill string coupled to a lower end of the internal pipe of the cross BOP swivel joint. The cross BOP swivel joint may be received through an opening in the at least one blowout preventer, and when the at least one blowout preventer is activated, the at least one blowout preventer may contact an outer surface of the swivel housing of the cross BOP swivel joint. 
     An eighteenth aspect of the present disclosure may include the seventeenth aspect, further comprising a drive system coupled to an upper end of the internal pipe of the cross BOP swivel joint. The drive system may be operable to rotate the drill string through the internal pipe connecting the drive system to the drill string, where the drill string may be rotated relative to the wellbore. 
     A nineteenth aspect of the present disclosure may include either one of the seventeenth or eighteenth aspects, where the at least one blowout preventer may be a pipe ram blowout preventer, an annular blowout preventer, of a combination of both. 
     A twentieth aspect of the present disclosure may include any one of the first through sixteenth aspects, and may be directed to a method of drilling a subterranean formation. The method may include operating a drill string in a wellbore, the drill string comprising the cross BOP swivel joint of any one of the first through sixteenth aspects. The method can further include sealing an annulus between the drill string and a wellbore wall of the wellbore by operating at least one blowout preventer disposed at a surface of the wellbore. The blowout preventer may engage with an outer surface of the swivel housing of the cross BOP swivel joint. The method may further include after sealing the annulus with the at least one blowout preventer, rotating the drill string in the wellbore. Engagement of the blowout preventer with the outer surface of the swivel housing may maintain the swivel housing in a static position. Rotating the drill string may cause the internal pipe of the cross BOP swivel joint to rotate relative to the swivel housing. The at least one central bearing may reduce deflection of the swivel housing radially inward towards the internal pipe. 
     A twenty-first aspect of the present disclosure may include the twentieth aspect, further comprising identifying a condition of the wellbore indicative of a wellbore kick, and in response to the condition indicative of the wellbore kick, operating the at least one blowout preventer to seal the annulus. 
     Additional features and advantages of the technology described in this disclosure will be set forth in the detailed description that follows, and in part will be readily apparent to those skilled in the art from the description or recognized by practicing the technology as described in this disclosure, including the detailed description that follows, the claims, as well as the appended drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following detailed description of specific embodiments of the present disclosure can be best understood when read in conjunction with the following drawings, where like structure is indicated with like reference numerals and in which: 
         FIG.  1    schematically depicts a drilling apparatus comprising at least a drilling rig and a drill string comprising a drill bit for drilling a wellbore through a subterranean formation, according to one or more embodiments shown and described in this disclosure; 
         FIG.  2    schematically depicts a front cross-sectional view of a blowout preventer stack of the drilling apparatus of  FIG.  1   , according to one or more embodiments shown and described in this disclosure; 
         FIG.  3    schematically depicts a top view of a pipe ram blowout preventer in a closed position, according to one or more embodiments shown and described in this disclosure; 
         FIG.  4    schematically depicts a top cross-sectional view of an annular blowout preventer in a closed position, according to one or more embodiments shown and described in this disclosure; 
         FIG.  5    schematically depicts a front cross-sectional view of a cross BOP swivel joint, according to one or more embodiments shown and described in this disclosure; 
         FIG.  6    schematically depicts a top cross-sectional view of the cross BOP swivel joint of  FIG.  5   , where the cross-section is taken along reference line  6 - 6  in  FIG.  5   , according to one or more embodiments shown and described in this disclosure; 
         FIG.  7    schematically depicts a drilling apparatus having the cross BOP swivel joint of  FIG.  5   , according to one or more embodiments shown and described in this disclosure; and 
         FIG.  8    schematically depicts a front cross-sectional view of the cross BOP swivel joint of  FIG.  5    with a pipe ram blowout preventer engaged with an outer surface of the cross BOP swivel joint, according to one or more embodiments shown and described in this disclosure. 
     
    
    
     Reference will now be made in greater detail to various embodiments of the present disclosure, some embodiments of which are illustrated in the accompanying drawings. Whenever possible, the same reference numerals will be used throughout the drawings to refer to the same or similar parts. 
     DETAILED DESCRIPTION 
     The present disclosure is directed to a cross BOP swivel joint for a drilling apparatus for drilling a wellbore through a subterranean formation. Referring to  FIG.  5   , one embodiment of the cross BOP swivel joint  100  of the present disclosure for crossing a blowout preventer (BOP) of a drilling apparatus is schematically depicted. The cross BOP swivel joint  100  comprises a swivel housing  110  and an internal pipe  130  received through the swivel housing  110 . The swivel housing  110  can comprise a hollow cylindrical wall  112  having a top end  120 , a bottom end  122 , an outer surface  114 , an inner surface  116  that defines an inner cavity  118  extending axially through the swivel housing  110 . The internal pipe  130  can be received through the inner cavity  118  of the swivel housing  110  and can include an upper loading shoulder  146  proximate the top end  120  of the swivel housing  110  and a lower loading shoulder  148  proximate the bottom end  122  of the swivel housing  110 . The cross BOP swivel joint  100  can include an upper journal bearing  162 , a lower journal bearing  164 , and at least one central bearing  170 , each of which is radially disposed between an outer surface  132  of the internal pipe  130  and the inner surface  116  of the cylindrical wall  112  of the swivel housing  110 . The upper journal bearing  162  can be axially disposed between the upper loading shoulder  146  of the internal pipe  130  and the top end  120  of the swivel housing  110 , and the lower journal bearing  164  can be axially disposed between the lower loading shoulder  148  of the internal pipe  130  and the bottom end  122  of the swivel housing  110 . The upper journal bearing  162  and the lower journal bearing  164  allow the internal pipe  130  to rotate relative to the swivel housing  110 . The at least one central bearing  170  can be axially disposed between the upper journal bearing  162  and the lower journal bearing  164 . The outer surface  114  of the swivel housing  110  contacts the BOP when the BOP is engaged with the cross BOP swivel joint  100 . The central bearing  170  provides radial support to the swivel housing  110  that can reduce deformation of the swivel housing  110  radially inward towards the internal pipe  130  when the BOP is engaged with the outer surface  114  of the swivel housing  110 . 
     As used throughout the present disclosure, the term “hydrocarbon-bearing formation” refers to a subterranean geologic region containing hydrocarbons, such as crude oil, hydrocarbon gases, or both, which may be extracted from the subterranean geologic region. The terms “subterranean formation” or just “formation” refer to a subterranean geologic region that contains hydrocarbons or a subterranean geologic region proximate to a hydrocarbon-bearing formation, such as a subterranean geologic region to be treated for purposes of enhanced oil recovery or reduction of water production or a subterranean geologic region that must be drilled through to get to the hydrocarbon-bearing formation. 
     As used in the present disclosure, the term “uphole” refers to a direction in a wellbore that is towards the surface. For example, a first component that is uphole relative to a second component is positioned closer to the surface of the wellbore relative to the second component. 
     As used in the present disclosure, the term “downhole” refers to a direction further into the formation and away from the surface. For example, a first component that is downhole relative to a second component is positioned farther away from the surface of the wellbore relative to the second component. The terms “uphole” and “downhole” are not intended to imply a vertical arrangement but rather are directions along a center axis of the wellbore relative to the surface. 
     As used throughout the present disclosure, the term “fluid” includes liquids, gases, or both and can include solids in combination with the liquids, gases, or both, such as but not limited to suspended solids in the wellbore fluids; entrained particles in gas produced from the wellbore; drilling fluids comprising weighting agents, lost circulation materials, cuttings, or other solids; or other mixed phase suspensions, slurries and other fluids. 
     As used in the present disclosure, a fluid passing from a first feature “directly” to a second feature refers to the fluid passing from the first feature to the second feature without passing or contacting a third feature intervening between the first and second feature. 
     As used throughout the present disclosure, the term “axial” refers to a direction in parallel to the central axis A of the cross BOP swivel joint and drill string. As used throughout the present disclosure, term “radial” refers to a direction that is perpendicular to and outward from the central axis A of the cross BOP swivel joint and drill string. As used throughout the present disclosure, the term “angular” refers to an angular position of a structure about the central axis A of the cross BOP swivel joint. 
     As used throughout the present disclosure, the term “well control event” refers to closure of the annulus of the wellbore, which is defined between the drill string and the wellbore wall or tubular casing, to prevent fluid flow from the annulus to the surface in response to wellbore conditions indicative of formation kick or blowout. 
     Referring now to  FIG.  1   , a wellbore  10  extending from the surface  12  into a subterranean formation  20  is schematically depicted. The wellbore  10  forms a pathway capable of permitting both fluids and apparatus to traverse between the surface  12  and the subterranean formation  20 , such as a hydrocarbon-bearing subterranean formation. Besides defining the void volume of the wellbore  10 , the wellbore wall  14  also acts as an interface through which fluid can transition between the subterranean formation  20  and the interior of the wellbore  10 . The wellbore wall  14  can be unlined (that is, bare rock or formation) to permit such interaction with the formation or lined, such as by a tubular casing  16 , to prevent such interactions. 
     The wellbore  10  provides a fluid conduit that links the interior of the wellbore  10  to the surface  12 . The fluid conduit connecting the interior of the wellbore  10  to the surface  12  can permit regulated fluid flow from the interior of the wellbore  10  to the surface  12  and access between equipment on the surface  12  and the interior of the wellbore  10 . Examples of equipment connected at the surface  12  to the fluid conduit can include but are not limited to pipelines, tanks, pumps, compressors, flares, or combinations of these. The fluid conduit may be large enough to permit introduction and removal of mechanical devices, including but not limited to tools, drill strings, sensors, instruments, or combinations of these into and out of the interior of the wellbore  10 . 
     Referring again to  FIG.  1   , a drilling apparatus  30  for drilling the wellbore  10  is schematically depicted. The drilling apparatus  30  can include, a drilling rig  40 , a drill string  50  operatively coupled to the drilling rig  40  and extending downhole into the wellbore  10 , and a drill bit  52  coupled to a downhole end of the drill string  50 . The drilling rig  40  is used in the present disclosure to refer to the part of the drilling apparatus  30  disposed at the surface  12 . The drilling apparatus  30  further includes a blowout preventer (BOP) stack  70 . The drill string  50  with the drill bit  52  is disposed downhole, and the drilling rig  40  operates to rotate the drill string  50 , thereby rotating the drill bit  52 . The drill string  50  generally includes a plurality of interconnected drill pipes extending from the surface  12  down into the wellbore  10  to the drill bit  52 . The drill string  50  has a center axis A. In the present disclosure, the axial direction refers to movement of components in an uphole or downhole direction parallel to the center axis A of the drill string  50 . The radial direction refers to a direction perpendicular to and outward from the center axis A of the drill string  50 . During certain stages in the life cycle of the wellbore, the drill string  50  can be replaced with one or more of a cement string, production tubing, injection tubing, or other equipment in the drilling apparatus  30 . 
     Rotation of the drill string  50  in the wellbore  10  and axial movement of the drill string  50  in the uphole and downhole directions during drilling is controlled by the drilling rig  40  disposed at the surface  12  of the wellbore  10 . The drilling rig  40  can include a swivel  42  coupled to the uphole end of the drill string  50 , a hoist system  44 , and a drive system  46 . The swivel  42  may be rigidly secured to an uphole end of the drill string  50 . The other end of the swivel  42  may be coupled to the hoist system  44 . The swivel  42 , which is different from the cross BOP swivel joint  100  of the present disclosure, may be operable to allow the drill string  50  to be rotated relative to the hoist system  44 . The hoist system  44  is coupled to the swivel  42  on the end of the swivel  42  opposite the drill string  50 . The hoist system  44  is operable to raise and lower the drill string  50  to translate the drill string  50  axially through the wellbore  10  in the uphole or downhole directions, respectively. The drive system  46  is operable to rotate the drill string  50  relative to the wellbore  10 . The drive system  46  can be a Kelly drive, a top drive, or other drive system. 
     Rotation of the drill string  50  in combination with the weight of the drill string  50  causes the drill bit  52  to bore into the bottom or downhole end of the wellbore  10  to extend the depth of the wellbore  10  into the subterranean formation  20 . While drilling, a drilling fluid  60  is typically circulated through the drill string  50  and the drill bit  52 . During operation of the drill bit  52 , the drilling fluid  60  is pumped through the inner conduit defined by the interconnected drill pipe of the drill string  50  to the drill bit  52 . The drilling fluids  60  flow from the drill string  50 , through the drill bit  52 , and out into the wellbore  10 . The drilling fluids  60  then flow back uphole through the wellbore  10  to the surface  12 . In particular, the drilling fluids  60  flow uphole through the annulus  18  defined between the wellbore wall  14  of the wellbore  10  and an outer surface of the drill string  50 . 
     Drilling fluids  60  are formulated to have rheological properties that enable the drilling fluids  60  to convey cuttings from the drill bit  52  at the downhole end of the wellbore  10  uphole to the surface  12 . Additionally, the drilling fluids  60  are formulated to provide hydrostatic forces within the wellbore  10  to support the wellbore wall  14  and provide resistance to the flow of formation fluids, such as hydrocarbon liquids, hydrocarbon gases, water, formation treatment fluids, or other fluids, from the subterranean formation  20  into the wellbore  10 . In particular, the drilling fluids  60  provide a hydrostatic force that is greater than or equal to the pressure of fluids in the subterranean formation  20  so that the hydrostatic force of the drilling fluid  60  resists flow of formation fluids into the wellbore  10 . This keeps the formation fluids in the subterranean formation  20  until the wellbore is completed and ready for production or injection. 
     Under certain conditions, the hydrostatic forces of the drilling fluid  60  and the pressure of the formation fluids become unbalanced. As previously discussed, imbalances between hydrostatic pressure of the drilling fluid  60  and formation pressure can result in formation fluids flowing from the subterranean formation, into the wellbore  10 , and upwards through the annulus  18  towards the surface  12 . These pressure imbalances that result in formation fluids flowing into the wellbore  10  is referred to as formation kick. The formation kick becomes a blowout when the formation fluids reach the surface  12 . 
     To control formation kick or respond to a blowout, the drilling apparatus  30  includes the BOP stack  70 , which is secured to the wellbore  10  at the junction of the wellbore  10  with the surface  12 . The BOP stack  70  includes one or a plurality of BOPs, which can include ram-type BOPs, annular BOPs, shear BOPs, blind BOPs, other types of BOPs, or combinations of these. The drill string  50  passes through the center of the BOP stack  70  and into the wellbore  10 . The BOPs of the BOP stack  70  are mechanical devices that seal the annulus  18  between the wellbore wall  14  and the outer surface of the drill string  50  to prevent formation fluids from reaching the surface  12  in the event of formation kick or to stop the flow of formation fluids out of the annulus  18  at the surface  12  during a blowout. During a well control event, such as formation kick or blowout, one or more of the BOPs in the BOP stack  70  are actuated to close the annulus  18  until the well control issue is remediated. 
     Referring now to  FIG.  2   , in embodiments, the BOP stack  70  can include one or more pipe-ram BOPs  80 , one or more annular BOPs  90 , or a combination of these. The pipe-ram BOP  80  can include two opposing rams  82  and two actuators  84  that operate to move each of the opposing rams  82  into and out of an engagement position. Referring to  FIGS.  2  and  3   , each of the rams  82  of the pipe-ram BOP  80  comprise an engagement surface  86  having a semi-cylindrical surface that is shaped to engage with the outer surface of the drill string  50  when the rams  82  are pressed together by the actuators  84 . The actuators  84  can be hydraulic cylinders or other actuating devices operable to move the rams  82  along a linear path between the engaged position and the disengaged position. 
     Referring to  FIG.  3   , in the engaged position, the rams  82  of the pipe-ram BOP  80  are moved toward each other until the rams  82  contact each other and contact the outer surface of the drill string  50 . In the engaged position, the pipe-ram BOP  80  closes off the annular space between the drill string  50  and the wellbore wall  14  to prevent fluid flow from the annulus  18  to the surface  12  while allowing fluid flow through center of the drill string  50 . The pipe-ram BOP  80  can have a resilient material on the engagement surfaces  86  of the rams  82 , the resilient material providing a seal around the outer surface of the drill string  50  when the pipe-ram BOP  80  is in the engaged position. The actuators  84  can also operate to move the rams  82  out of the engaged position to a disengaged positon to reopen the annulus  18 , such as to reopen the annulus  18  to resume drilling operations once the well control event is corrected. 
     Referring again to  FIG.  2   , in embodiments, the BOP stack  70  can include an annular BOP  90 . In embodiments, an annular BOP  90  can comprise a housing  92 , a sealing member  94 , and a piston  96 . The drill string  50  passes through the axial center of the annular BOP  90 . The sealing member  94  is disposed within the housing  92 . The sealing member  94  can be an elastomeric ring. The piston  96  can be actuated to reduce the volume of an internal chamber of the annular BOP  90  and deform or squeeze the sealing member  94  into engagement with the outer surface of the drill string  50 . In the engagement position, the sealing member  94  is squeezed or forced into contact with the outer surface of the drill string  50  to seal the annulus  18  between the drill string  50  and the wellbore wall  14 . The annular BOP  90  can be opened by moving the piston  96  back into the original position to open up the internal cavity within the annular BOP  90  and relieve the pressure on the sealing member  94  against the outer surface of the drill string  50 . 
     Referring now to  FIGS.  3  and  4   , for the pipe-ram BOP  80  and the annular BOP  90 , engagement of the BOP results in contact between a portion of the BOP (ram  82  of the pipe-ram BOP  80 , sealing member  94  of the annular BOP  90 ) and the outer surface of the drill string  50  that can restrict or prohibit rotation of the drill string  50  during a well control event or well shut-in. As a result, generally the drill string  50  cannot be rotated during a well control even or well shut-in. The inability to rotate the drill string  50  can result in differential sticking of the drill string  50  in the wellbore  10 . Differential sticking is caused by having high hydrostatic overbalance of the pressure of the wellbore fluids against the pore pressure of the subterranean formation  20 , which can push the drill sting  50  against the wellbore wall  14  and prevent pipe movement. High hydrostatic overbalance can occur when remediating the well control event. Differential sticking of the drill string  50  in the wellbore  10  requires expensive and lengthy fishing operations to release the stuck drill string  50 . In many cases, the drill string  50  and bottom hole assembly (BHA) (drill bit, under reamer, drill collar, and other associated equipment) cannot be recovered by fishing and the wellbore  10  has to be abandoned to sidetrack the well into a new direction. Being able to continuously rotate the drill string  50  during well control events and well shut-in can reduce or prevent differential sticking of the drill string  50 . Thus, ongoing needs exist for cross BOP swivel joints for enabling efficient rotation of the drill string  50  during well control events or well shut-in. 
     The present disclosure is directed to a cross BOP swivel joint for crossing the BOP stack  70  and enabling efficient and unrestricted rotation of the drill string  50  during well control events or well shut-in when the BOPs are engaged to seal off the annulus. Enabling efficient and unrestricted rotation of the drill string  50  in the wellbore  10  when the BOPs are activated can prevent extended stationary time of drill string  50  and drill BHA across the open hole and allow continuous rotation during well control events, well shut-in and killing operations. Enabling efficient and unrestricted rotation of the drill string  50  during well control events can reduce or prevent differential sticking of the drill string  50  and BHA against the porous permeable subterranean formation. Once the well is put back under control with proper kill mud in the wellbore  10 , the BOPs can be opened and the drill string  50  can be free to rotate to resume drilling operations. 
     Referring now to  FIG.  5   , the cross BOP swivel joint  100  of the present disclosure can include a swivel housing  110 , an internal pipe  130  received axially through the swivel housing  110 , journal bearings  160  disposed radially between the swivel housing  110  and the internal pipe  130  and disposed axially proximate to each end of the swivel housing  110 , and at least one central bearing  170  axially disposed between the journal bearings  160 . The swivel housing  110  provides an outer surface  114  that engages with the BOPs when engaged. The internal pipe  130  is secured at both ends to the drill string  50  or other equipment, such as but not limited to a cement string, production tubing, injection tubing, drive system, or combinations of these. The cross BOP swivel joint  100  can further include a plurality of seals  180  disposed radially between the swivel housing  110  and the internal pipe  130 . The cross BOP swivel joint  100  can further include one or a plurality of ports  190  in the swivel housing  110 . 
     The journal bearings  160  and the at least one central bearing  170  allow the internal pipe  130  to rotate relative to the swivel housing  110  when the BOPs are actuated during a well control event. Thus, when engagement of the pipe ram BOP, annular BOP, or both with the outer surface  114  of the swivel housing  110  restricts or inhibits rotation of the swivel housing  110 , the internal pipe  130  and drill string  50 , which is secured to the internal pipe  130 , can still rotate relative to the swivel housing  110 . In some cases, the pressure of the pipe ram BOPS, annular BOPs, or both on the outer surface  114  of the swivel housing  110  can deflect the swivel housing  110  radially inward, which can cause the swivel housing  110  to contact and interfere with rotation of the internal pipe  130 . The central bearing(s)  170  of the cross BOP swivel joint  100  can provide radial support to the swivel housing  110  to reduce or prevent the pipe ram BOP or annular BOP from deflecting the swivel housing  110  radially inward and interfering with rotation of the internal pipe  130 , thus, maintaining efficient rotation of the internal pipe  130  relative to the swivel housing  110 . Additionally, the central bearing(s)  170  can further stabilize rotation of the internal pipe  130  by providing an additional bearing disposed between the two journal bearings  160 , which provides an additional contact point. 
     Referring again to  FIG.  5   , the swivel housing  110  can include a hollow cylindrical wall  112  having the outer surface  114  and an inner surface  116 . The inner surface  116  defines an inner cavity  118  extending axially through the swivel housing  110 . In embodiments, the inner cavity  118  may be centered on the center axis A of the drill string  50 . The swivel housing  110  has a top end  120  and a bottom end  122 , where the top end  120  is the end oriented in the uphole direction towards to the drilling rig  40  and the bottom end  122  is the end of the swivel housing  110  oriented in the downhole direction towards the wellbore  10 . The outer surface  114  of the swivel housing  110  may have a shape that compliments a shape of the engagement surface  86  ( FIG.  3   ) of the pipe-ram BOP  80 . Referring to  FIG.  6   , in embodiments, the outer surface  114  of the swivel housing  110  can have a circular cross-sectional shape. 
     Referring again to  FIG.  5   , the inner surface  116  of the swivel housing  110  can include an upper restriction  124  proximate to the top end  120  of the swivel housing  110 , a lower restriction  126  proximate the bottom end  122  of the swivel housing  110 , and a central wall  128  extending axially between the upper restriction  124  and the lower restriction  126 . The upper restriction  124  and lower restriction  126  can comprises portions of the cylindrical wall  112  where the inner surface  116  has an inner diameter that is less than the inner diameter of the central wall  128 . At the upper restriction  124  and the lower restriction  126 , the inner surface  116  of the swivel housing  110  is radially disposed close to an outer surface  132  of the internal pipe  130  to create a restriction to reduce fluid flow between the swivel housing  110  and the internal pipe  130  at the top end  120  and the bottom end  122  of the swivel housing  110 . The central wall  128  is radially spaced apart from the internal pipe  130  so that the inner surface  116  of the swivel housing  110  and the outer surface  132  of the internal pipe  130  define at least one annular compartment  150  disposed radially between the swivel housing  110  and the internal pipe  130 . The annular compartment  150  may provide the radial clearance to accommodate the journal bearings  160  and central bearings  170  disposed between the internal pipe  130  and the swivel housing  110 . 
     Referring again to  FIG.  5   , the cross BOP swivel joint  100  comprises the internal pipe  130  extending axially through the inner cavity  118  of the swivel housing  110 . The internal pipe  130  comprises an outer surface  132  facing radially outward towards the inner surface  116  of the swivel housing  110 . The outer surface  132  of the internal pipe  130  may have a cross sectional shape that is circular, particularly in places where the outer surface  132  engages with the journal bearings  160  and the central bearings  170 . In embodiments, the internal pipe  130  may be centered on the center axis A of the drill string  50  so that the internal pipe  130  is coaxial with the swivel housing  110 . The internal pipe  130  can further include an internal conduit  134  that extends axially through the internal pipe  130 . The internal conduit  134  provides a fluid pathway through the cross BOP swivel joint  100  for passing materials and/or instruments axially through the cross BOP swivel joint  100  between the wellbore  10  and the surface  12 . 
     When assembled, the swivel housing  110  surrounds at least a portion of the internal pipe  130 . The internal pipe  130  can extend axially beyond the top end  120  and the bottom end  122  of the swivel housing  110 . The internal pipe  130  can further include an upper end  136  and a lower end  138 . The upper end  136  of the internal pipe  130  may be disposed vertically above the top end  120  of the swivel housing  110 , such as uphole relative to the top end  120  of the swivel housing  110 . The lower end  138  of the internal pipe  130  may be disposed vertically below the bottom end  122  of the swivel housing  110 , such as downhole relative to the bottom end  122  of the swivel housing  110 . The internal pipe  130  can include connections at the upper end  136  and lower end  138 , where the connections can operate to rigidly secure the internal pipe  130  to the drill string  50  at each end of the internal pipe  130 . In embodiments, the internal pipe  130  can include a box connection  140  at the upper end  136  and a pin connection  142  at the lower end  138  of the internal pipe  130 . The upper end  136  and lower end  138  of the internal pipe  130  can each have any other suitable type of connection operable to rigidly secure the internal pipe  130  to the drill string  50 . The connections, such as box connection  140  and pin connection  142 , can also couple the internal pipe  130  to other structures, such as a cement string, a Kelly of a Kelly drive system, the swivel  42 , production tubing, injection tubing, or other equipment useful for drilling the wellbore  10 , completing the wellbore  10 , producing hydrocarbons from the wellbore  10 , injecting treatment fluids into the subterranean formation from the wellbore  10 , or closing a wellbore  10 . 
     Referring again to  FIG.  5   , the internal pipe  130  can further include an upper loading shoulder  146  disposed axially proximate the upper restriction  124  of the swivel housing  110  and a lower loading shoulder  148  disposed axially proximate the lower restriction  126  of the swivel housing  110 . The upper loading shoulder  146  and the lower loading shoulder  148  may extend radially outward from the internal pipe  130 . The upper loading shoulder  146  and the lower loading shoulder  148  may include abutment surfaces that can restrict axial travel of the internal pipe  130  relative to the swivel housing  110 . The abutment surfaces of the upper loading shoulder  146  and the lower loading shoulder  148  may abut against the journal bearings  160  or the upper restriction  124  or lower restriction  126  of the swivel housing  110  to restrict axial movement of the internal pipe  130  relative to the swivel housing  110 . 
     Referring again to  FIG.  5   , the cross BOP swivel joint  100  comprises two journal bearings  160  that facilitate rotation of the internal pipe  130  relative to the swivel housing  110 . The journal bearings  160  can comprise an upper journal bearing  162  and a lower journal bearing  164 . The upper journal bearing  162  and the lower journal bearing  164  are radially disposed between the inner surface  116  of the swivel housing  110  and the outer surface  132  of the internal pipe  130 . The journal bearings  160  can be any type of journal bearing operable to enable rotation of the internal pipe  130  relative to the swivel housing  110 . 
     The upper journal bearing  162  may be axially disposed proximate to the top end  120  of the swivel housing  110 , such as between the upper loading shoulder  146  of the internal pipe  130  and the top end  120  of the swivel housing  110 . In embodiments, the upper journal bearing  162  may be axially disposed within the annular compartment  150  between the upper loading shoulder  146  of the internal pipe  130  and the upper restriction  124  of the swivel housing  110 . The lower journal bearing  164  may be axially disposed proximate to the bottom end  122  of the swivel housing  110 , such as between the lower loading shoulder  148  of the internal pipe  130  and the bottom end  122  of the swivel housing  110 . In embodiments, the lower journal bearing  164  may be axially disposed within the annular compartment  150  between the lower loading shoulder  148  of the internal pipe  130  and the lower restriction  126  of the swivel housing  110 . 
     The upper journal bearing  162  and the lower journal bearing  164  can enable the internal pipe  130  to rotate relative to the swivel housing  110 . In embodiments, each of the journal bearings  160  can be rigidly secured to the inner surface  116  of the swivel housing  110 , and the internal pipe  130  can be slidably received through each of the journal bearings  160  so that the internal pipe  130  can rotate relative to the swivel housing  110 . In embodiments, the journal bearings  160  can be slideable relative to the outer surface  132  of the internal pipe  130  and the inner surface  116  of the swivel housing  110 . The journal bearings  160  can restrict axial movement of the cross BOP swivel joint  100  relative to the BOP stack  70 . Axial movement of the cross BOP swivel joint  100  when the BOP stack  70  is activated can cause the cross BOP swivel joint  100  to accidently be pulled out of the BOP stack  70 . This can lead to leakage of hydrocarbons to the atmosphere or to damaging the seals of the ram BOP  80 . 
     Referring again to  FIG.  5   , the cross BOP swivel joint  100  can further include one or a plurality of central bearings  170 . The central bearings  170  can be radially disposed between the outer surface  132  of the internal pipe  130  and the inner surface  116  of the cylindrical wall  112  of the swivel housing  110 . The central bearings  170  may be disposed within the annular compartment  150  defined between the swivel housing  110  and the internal pipe  130 . The central bearings  170  may be axially disposed between the upper journal bearing  162  and the lower journal bearing  164 . The one or plurality of central bearings  170  can provide radial support to the swivel housing  110  that reduces deformation of the swivel housing  110  radially inward towards the internal pipe  130  when a BOP is engaged with the outer surface  114  of the swivel housing  110 . The central bearings  170  can also provide further stability to rotation of the internal pipe  130  relative to the swivel housing  110 . 
     The central bearings  170  can be any type of bearing operable to reduce or prevent deflection of the swivel housing  110  radially inward towards the internal pipe  130  while also allowing efficient rotation of the internal pipe  130  relative to the swivel housing  110 . Examples of bearings suitable for the central bearings  170  can include but are not limited to ball bearings, roller bearings, thrust ball bearings, thrust roller bearings, other types of bearings, or combinations of these. In embodiments, journal bearings may not be suitable for use as the central bearings  170 . Not intending to be bound by any particular theory, it is believed that the radial forces of the BOP against the swivel housing  110  would create increased friction in a journal bearing that would increase resistance to rotation of the internal pipe  130  relative to the swivel housing  110 . In embodiments, the central bearings  170  can be ball bearings. The ball bearings can include an outer race secured to the inner surface  116  of the swivel housing  110 , an inner race secured to the outer surface  132  of the internal pipe  130 , and a plurality of rigid balls disposed between the inner race and the outer race. The ball bearing can reduce deformation of the swivel housing  110  radially inward towards the internal pipe  130  when a blowout preventer is engaged with the outer surface  114  of the swivel housing  110  while at the same time stabilizing rotation of the internal pipe  130  relative to the swivel housing  110 . 
     As previously discussed, the central bearings  170  are axially disposed between the upper journal bearing  162  and the lower journal bearing  164 . The swivel housing  110  may have an axial center B that refers to a point of the swivel housing that is axially halfway between the upper journal bearing  162  and the lower journal bearing  164 . In other words, an axial length L of the swivel housing  110  is defined as the axial distance between the upper journal bearing  162  and the lower journal bearing  164 , and the axial center B is the point where the distance from the axial center B to the upper journal bearing  162  is the same as the distance from the axial center B to the lower journal bearing  164 . The central bearings  170  may be axially disposed close enough to the axial center B to reduce or prevent deflection of the swivel housing  110  radially inward towards the internal pipe  130 . When the central bearings  170  are disposed too close to the journal bearings  160 , the center part of the swivel housing  110  proximate the axial center B may not have sufficient radial support to prevent deflection of the swivel housing  110  from interfering with rotation of the internal pipe  130 . In embodiments, each of the central bearings  170  can be axially disposed at a distance from the axial center B of the swivel housing  110  that is less than 40%, less than or equal to 35%, less than or equal to 30%, less than or equal to 25%, or even less than or equal to 20% of the axial length L between the upper journal bearing  162  and the lower journal bearing  164 . 
     In embodiments, the cross BOP swivel joint  100  can include a plurality of central bearings  170  that are spaced apart from each other and distributed axially between the upper journal bearing  162  and the lower journal bearing  164 . When the cross BOP swivel joint  100  includes a plurality of central bearings  170 , each of the plurality of central bearings  170  can be axially positioned at a distance from the axial center B of the swivel housing  110  that is less than 40%, less than or equal to 35%, less than or equal to 30%, or even less than or equal to 25% of the axial length L between the upper journal bearing  162  and the lower journal bearing  164 . Evenly distributing the central bearings  170  throughout the annular compartment  150  between the journal bearings  160  can further reduce or prevent deflection of the swivel housing  110  radially inward and can further stabilize rotation of the internal pipe  130  relative to the swivel housing  110 . 
     Referring again to  FIG.  5   , the cross BOP swivel joint  100  can further include a plurality of seals  180  disposed radially between the inner surface  116  of the swivel housing  110  and the outer surface  132  of the internal pipe  130 . The seals  180  can be disposed in an annular gap between the inner surface  116  of the swivel housing  110  and the outer surface  132  of the internal pipe  130 . The seals  180  can seal the annular gap between the swivel housing  110  and the internal pipe  130  to restrict or prevent fluid flow through the annular gap and into the annular compartment  150 . Thus, the seals  180  prevent fluid from the annulus of the wellbore  10  from bypassing the BOP by flowing through the gap between the internal pipe  130  and the swivel housing  110  of the cross BOP swivel joint  100 . The seals  180  may fluidly isolate the annular compartment  150  between the swivel housing  110  and the internal pipe  130  from the wellbore annulus and from the atmosphere at the surface  12 . The seals  180  may comprise a resilient material that allows the internal pipe  130  to rotate relative to the swivel housing  110  while preventing fluid flow between the swivel housing  110  and the internal pipe  130 . In embodiments, the seals  180  can be gaskets, o-rings or other structures comprising the resilient materials. In embodiments, the seals  180  can include one or more mechanical seals. Other types of suitable commercially available seals are contemplated. 
     The plurality of seals  180  can include upper seals and lower seals. The upper seals can be disposed axially between the upper journal bearing  162  and the top end  120  of the swivel housing  110 , such as axially in the upper restriction  124  of the swivel housing  110  and radially between the upper restriction  124  and the internal pipe  130 . The lower seals can be disposed axially between the lower journal bearing  164  and the bottom end  122  of the swivel housing  110 , such as axially in the lower restriction  126  of the swivel housing  110  and radially between the lower restriction  126  and the internal pipe  130 . In embodiments, the cross BOP swivel joint  100  can include additional seals  180  axially disposed between the journal bearings  160 . In embodiments, the seals  180  can include a plurality of internal seals disposed axially between the journal bearings  160 . In embodiments, the internal seals can be disposed between at least one central bearing  170  and the upper journal bearing  162 , between at least one central bearing  170  and the lower journal bearing  164 , between two central bearings  170  or combinations of these. 
     Referring again to  FIG.  5   , the plurality of seals  180 , in particular the internal seals, can divide the annular compartment  150  into a plurality of annular compartments that are fluidly isolated from one another. In embodiments, each of the annular compartments can be separated from one another by one of the central bearings  170  as well as by the seals  180 . Each of the annular compartments can include a lubricant, such as a synthetic or natural oil, grease, or other lubricant. The lubricant may provide lubrication to the central bearings  170 , the journal bearings  160 , or both. The lubricant may further provide a hydrostatic barrier on the inside of the seals  180  to further resist penetration of drilling fluids and formation fluids through the seals and into the annular compartments  150 . 
     The cross BOP swivel joint  100  can further include one or a plurality of ports  190  in the swivel housing  110 . The ports  190  can extend radially through the swivel housing  110 . The each of the ports  190  can be in fluid communication with at least one of the annular compartments  150  between the internal pipe  130  and the swivel housing  110 . The ports  190  may enable lubricant materials to be dispensed into the annular compartments  150 . Additionally, the ports  190  can further enable inspection of the annular compartments  150 , measurement of pressure within each of the annular compartments  150 , or both. For example, the ports  190  can enable sampling of the lubricants, which can be used to determine whether drilling fluids or formation fluids have penetrated through any of the seals  180 . The ports  190  may enable other maintenance activities or measurements, such as temperature, pressure, or other property. 
     Referring now to  FIG.  7   , the cross BOP swivel joint  100  of the present disclosure can be incorporated into the drilling apparatus  30  for drilling the wellbore  10 . The drilling apparatus  30  can include the drilling rig  40 , a BOP stack  70  comprising at least one BOP, the cross BOP swivel joint  100 , and the drill string  50  coupled to the lower end  138  of the internal pipe  130  of the cross BOP swivel joint  100 . The cross BOP swivel joint  100  can be received through a central opening through the at least one BOP in the BOP stack  70 . When the at least one BOP in the BOP stack  70  is activated, the BOP contacts the outer surface  114  of the swivel housing  110  of the cross BOP swivel joint  100 . Cross BOP swivel joint  100  can include any of the features previously discussed in the present disclosure for the cross BOP swivel joint  100 . As previously discussed, the BOP stack  70  can include one or a plurality of pipe-ram BOPS  80 , one or a plurality of annular BOPs  90 , or combinations of these. In embodiments, the BOP stack  70  may further include a blind ram BOP, a shear ram BOP, or other type of BOP. It is noted that blind ram BOPs and shear ram BOPs are generally not designed to interact or engage with the outer surface of the drill string  50 . For instance, a blind ram BOP is generally designed to close the entirety of the wellbore when no drill string  50  is disposed in the wellbore  10 , and a shear ram BOP is generally designed to sever the drill string  50  to completely seal the wellbore  10 . 
     The drill string  50  can include a drill bit  52  secured to the downhole end of the drill string  50 . The drill string  50  can further include a bottom hole assembly comprising the drill bit, underreamers, drill collars, and other downhole equipment. As previously discussed, the drilling rig  40  can include the drive system  46 . The drive system  46  can be secured to the upper end  136  of the internal pipe  130  of the cross BOP swivel joint  100 . The drive system  46  can be operable to rotate the drill string  50  through the internal pipe  130  connecting the drive system  46  to the drill string  50 . The drive system  46  rotates the internal pipe  130  and drill string  50  relative to the wellbore wall  14 . The drive system  46  can be a top drive system, a Kelly drive system, or other type of drive system. As previously discussed, the drilling rig  40  can further include the swivel  42  and the hoist system  44 . In embodiments, the drive system  46  can be a top drive system, and the swivel  42  can be disposed between the drive system  46  and the cross BOP swivel joint  100  and can be secured to the upper end  136  of the internal pipe  130  and to the hoist system  44 . In embodiments, the drive system  46  can be a Kelly drive system, and the swivel  42  can be disposed between a Kelly of the Kelly drive system and the hoist system  44 . For a Kelly drive system, the Kelly of the Kelly drive system can be secured to the upper end  136  of the internal pipe  130  of the cross BOP swivel joint  100 . 
     Referring now to  FIGS.  7  and  8   , operation of the cross BOP swivel joint  100  during a well control event will be discussed. During normal operation, the drill but  52  is operated in the wellbore  10  by rotating the drill string  50  relative to the wellbore wall  14  using the drive system  46 . During normal operation, the swivel housing  110  and internal pipe  130  of the cross BOP swivel joint  100  both can rotate relative to the wellbore wall  14 . 
     The drilling apparatus  30  can further include a plurality of instruments (not shown) coupled to various components of the drill string  50  or to the drilling apparatus  30 . The instruments can be used to identify a condition of the wellbore  10  indicating the undesired flow of formation fluids from the subterranean formation  20  into the wellbore  10 , such as resulting from formation kick or other upset condition. Undesired flow of formation fluids into the wellbore refers to the flow of formation fluids into the wellbore during drilling or completion of the wellbore and does not include purposeful production of hydrocarbons from the subterranean formation  20  after well completion. The conditions indicating flow of formation fluids into the wellbore  10  can include monitoring the pressure of the wellbore, the composition of the drilling fluids  60  returned to the surface  12 , or other operating condition of the wellbore  10 . 
     Identifying the undesired flow of formation fluids into the wellbore can initiate a well control event. Referring to  FIG.  8   , upon identifying a condition indicating the undesired flow of formation fluids into the wellbore  10 , initiating the well control event can include actuating one or more of the pipe-ram BOPs  80 , annular BOPs  90  ( FIG.  7   ), or both of the BOP stack  70  to engage with the outer surface  114  of the swivel housing  110 . Engagement of the pipe-ram BOP  80 , annular BOP  90 , or both, seals off the annulus  18  of the wellbore  10 , which prevents the flow of drilling fluids  60 , formation fluids, or both through the annulus  18  towards the surface  12 . Engagement of the pipe-ram BOP  80 , the annular BOP  90 , or both results in contact of the engagement surface  86  of the pipe-ram BOP  80  or sealing member  94  of the annular BOP  90  with the outer surface  114  of swivel housing  110 , which reduces or prevents the rotation of the swivel housing  110  relative to the BOP stack  70  and the wellbore wall  14 . 
     The journal bearings  160  and central bearings  170  of the cross BOP swivel joint  100  allow continued rotation of the internal pipe  130  of the cross BOP swivel joint  100  relative to the BOP stack  70  when the BOPs are engaged with the outer surface  114  of the swivel housing  110 . Additionally, the central bearings  170  can reduce or prevent deflection of the swivel housing  110  radially inward towards the internal pipe  130  caused by engagement of the BOPs. Thus, during the well control event in which the BOPs are engaged with the swivel housing  110 , the drive system  46  can still be operated to rotate the internal pipe  130  of the cross BOP swivel joint  100  and the drill string  50  coupled to the lower end  138  of the internal pipe  130 . 
     The cause of the flow of wellbore fluids into the wellbore can be remediated, such as by adjusting the pressure of drilling fluid in the wellbore. Following remediation, the BOPs in the BOP stack  70  can be actuated to disengage the BOPs from the outer surface  114  of the swivel housing  110  to allow the flow of drilling fluids through the annulus  18  of the wellbore  10  back to the surface  12 . 
     In embodiments, the BOP stack  70  can include at least one annular BOP  90  and at least one pipe ram BOP  80  disposed downhole from the annular BOP  90 , and the cross BOP swivel joint  100  can have a swivel housing  110  that extends across the annular BOP  90  but not across the pipe ram BOP  80 . In this configuration, the annular BOP  90 , when engaged, contacts and seals around the outer surface  114  of the swivel housing  110 , and the ram BOP  80  closes on the drill string  50  downhole of the cross BOP swivel joint  100 . During operation, the annular BOP  90  can be engaged in response to a well control event. When engaged, the annular BOP  90  closes around the outer surface  114  of the swivel housing  110  to close off the annulus  18 . The well control event can then be remediated while the drill string  50  is rotated to prevent differential sticking of the drill string  50  in the wellbore  10 . Once the well control even is remediated, the annular BOP  90  can be disengaged to resume normal operation. 
     In case of a leak forming in the cross-BOP swivel joint  100  or between the cross BOP swivel joint  100  and the annular BOP  90 , the pipe ram BOP  80  can be engaged at a backup. When engaged, the pipe ram BOP  80  engages with the drill string  50  downhole from the cross BOP swivel joint  100  to re-seal the annulus  18 . However, engagement of the pipe ram BOP  80  with the drill string  50  will then prevent rotation of the drill string  50  during the well control event. 
     The cross BOP swivel joint  100  of the present disclosure can be employed in methods of drilling a wellbore in a subterranean formation. Referring again to  FIG.  7   , the methods can include operating the drill string  50  in a wellbore  10 , the drill string  50  comprising the cross BOP swivel joint  100  of the present disclosure and at least a drill bit  52 . The methods can further include sealing the annulus  18  defined between the drill string  50  and the wellbore wall  14  of the wellbore  10 . Sealing the annulus  18  can include operating at least one BOP disposed at the surface  12  of the wellbore  10 . When actuated, the BOP engages with the outer surface  114  of the swivel housing  110  of the cross BOP swivel joint  100 . In embodiments, the BOP can be a pipe ram BOP  80 , an annular BOP  90 , or both. Engagement of the BOP with the outer surface  114  of the swivel housing  110  can maintain the swivel housing  110  in a static position (not rotating). The methods can further include, after sealing the annulus  18  with the at least one BOP, rotating the drill string  50  in the wellbore  10 . Rotating the drill string  50  can cause the internal pipe  130  of the cross BOP swivel joint  100  to rotate relative to the swivel housing  110 . In embodiments, the at least one central bearing  170  can reduce deflection of the swivel housing  110  radially inward towards the internal pipe  130  when the BOP is engaged with the outer surface  114  of the swivel housing  110 . 
     In embodiments, the methods can further include identifying a condition of the wellbore  10  indicative of wellbore kick or possible blowout, and in response to the condition indicative of the wellbore kick or possible blowout, operating the at least one BOP to seal the annulus  18  of the wellbore  10 . In embodiments, the methods can further include correcting or compensating for the conditions of the wellbore indicative of the formation kick or possible blowout. Following correction of the conditions indicative of the well control event, re-opening the annulus  18  by disengaging the BOPs from the swivel housing  110 . 
     It is noted that one or more of the following claims utilize the terms “where,” “wherein,” or “in which” as transitional phrases. For the purposes of defining the present technology, it is noted that these terms are introduced in the claims as an open-ended transitional phrase that are used to introduce a recitation of a series of characteristics of the structure and should be interpreted in like manner as the more commonly used open-ended preamble term “comprising.” 
     It should be understood that any two quantitative values assigned to a property may constitute a range of that property, and all combinations of ranges formed from all stated quantitative values of a given property are contemplated in this disclosure. 
     Having described the subject matter of the present disclosure in detail and by reference to specific embodiments, it is noted that the various details described in this disclosure should not be taken to imply that these details relate to elements that are essential components of the various embodiments described in this disclosure, even in cases where a particular element is illustrated in each of the drawings that accompany the present description. Rather, the claims appended hereto should be taken as the sole representation of the breadth of the present disclosure and the corresponding scope of the various embodiments described in this disclosure. Further, it will be apparent that modifications and variations are possible without departing from the scope of the appended claims.