Patent Publication Number: US-11391107-B2

Title: Fluid management systems and related methods of controlling fluid flow in oil and gas applications

Description:
TECHNICAL FIELD 
     This disclosure relates to fluid management systems, such as blowout preventers, and related methods of controlling fluid flow at a wellbore. 
     BACKGROUND 
     During certain operations performed at a wellbore, formation fluid within an annular region that surrounds a pipe of a tubing string disposed within the wellbore may begin to flow uncontrollably in an uphole direction, thereby posing the risk of a blowout of the wellbore. Blowout preventers are designed to seal around a pipe during wellbore control situations in order to contain the pressure of the formation fluid within the wellbore and therefore avoid uncontrolled flow of the formation fluid from the wellbore. However, in some cases, a blowout preventer may fail to activate (for example, fail to close the wellbore) due to any number of system failures. In such situations, the safety of a rig at the wellbore is significantly compromised. 
     SUMMARY 
     This disclosure relates to a blowout preventer including a mechanical activation system that is operable to close a pipe ram assembly around a drill pipe disposed within a wellbore to prevent uncontrolled, uphole-directed fluid flow from the wellbore around the drill pipe. The mechanical activation system is a contingency system that can be utilized in case a primary hydraulic activation system of the blowout preventer fails to close two cooperating pipe ram blocks of the pipe ram assembly around the drill pipe for any reason. For each pipe ram block, the mechanical activation system includes an activation shaft that is coupled to the pipe ram block and translatable to move the pipe ram block linearly, a drive shaft that is coupled to the activation shaft and rotatable to cause translation of the activation shaft along the drive shaft, a drive loop that is translatable along the drive shaft to rotate the drive shaft, and a pneumatic motor that is operable to activate the drive loop. 
     The drive shaft has a threaded exterior profile by which the drive loop engages the drive shaft to rotate the drive shaft. The threaded exterior profile of the drive shaft also engages a threaded interior profile of the activation shaft that causes the activation shaft to translate as the drive shaft rotates. Inwardly directed translation of the activation shafts causes the pipe ram blocks to close against each other around the drill pipe, whereas outwardly directed translation of the activation shafts causes the pipe ram blocks to move away from each other and from the drill pipe. 
     In one aspect, a fluid management system for controlling fluid flow at a wellbore includes a closing element formed complementary to a drill pipe disposed within the wellbore and an activation system. The activation system is configured to move the closing element into an activated position against the drill pipe to close the wellbore around the drill pipe for preventing fluid from flowing out of the wellbore. The activation system includes an activation shaft coupled to the closing element and a rotatable drive shaft configured to cause translation of the activation shaft to push the closing element into the activated position against the drill pipe. 
     Embodiments may provide one or more of the following features. 
     In some embodiments, the fluid management system further includes a drive loop coupled to the rotatable drive shaft and a pneumatic motor that controls the drive loop. 
     In some embodiments, the rotatable drive shaft is rotatable in a first direction to move the closing element into the activated position. 
     In some embodiments, the rotatable drive shaft is rotatable in a second direction to allow the closing element to move from the activated position to a deactivated position that is spaced apart from the drill pipe to expose the wellbore around the drill pipe, and the second direction is opposite to the first direction. 
     In some embodiments, the activation shaft includes an interior threaded profile, and the rotatable drive shaft includes an exterior threaded profile that is formed to engage the interior threaded profile of the activation shaft. 
     In some embodiments, interior threaded profile and the exterior threaded profile include square threads. 
     In some embodiments, the closing element is a first closing element, the activation shaft is a first activation shaft, the rotatable drive shaft is a first rotatable drive shaft, the activated position is a first activated position, the fluid management system further includes a second closing element that is configured to cooperate with the first closing element to close the wellbore around the drill pipe, and the activation system further includes a second activation shaft coupled to the second closing element and a second rotatable drive shaft configured to cause translation of the second activation shaft to push the second closing element into a second activated position against the drill pipe. 
     In some embodiments, the closing element includes a pipe ram block. 
     In some embodiments, the activation system includes a contingency activation system, and the fluid management system further includes a hydraulic activation system that is configured to move the closing element into the activated position against the drill pipe to close the wellbore around the drill pipe for preventing the fluid from flowing out of the wellbore. 
     In some embodiments, the fluid management system is configured to operate the contingency activation system to move the closing element into the activated position against the drill pipe upon failure of the hydraulic activation system. 
     In another aspect, a method of controlling fluid flow at a wellbore includes providing a closing element of a fluid management system at the wellbore, the closing element being formed complementary to a drill pipe disposed within the wellbore. The method further includes rotating a drive shaft of an activation system of the fluid management system and translating an activation shaft of the activation system, the activation shaft being coupled to the drive shaft and to the closing element. The method further includes pushing the closing element into an activated position against the drill pipe to close the wellbore around the drill pipe for preventing fluid from flowing out of the wellbore. 
     Embodiments may provide one or more of the following features. 
     In some embodiments, the method further includes operating a pneumatic motor of the activation system to activate a drive loop of the activation system, the drive loop being coupled to the drive shaft. 
     In some embodiments, the method further includes rotating the drive shaft in a first direction to move the closing element into the activated position. 
     In some embodiments, the method further includes rotating the drive shaft in a second direction to allow the closing element to move from the activated position to a deactivated position that is spaced apart from the drill pipe to expose the wellbore around the drill pipe, wherein the second direction is opposite to the first direction. 
     In some embodiments, the activation shaft includes an interior threaded profile, and the drive shaft includes an exterior threaded profile that is formed to engage the interior threaded profile of the activation shaft. 
     In some embodiments, the interior threaded profile and the exterior threaded profile include square threads. 
     In some embodiments, the closing element is a first closing element, the activation shaft is a first activation shaft, the drive shaft is a first drive shaft, the activated position is a first activated position, and the method further includes providing a second closing element of the fluid management system, the second closing element being configured to cooperate with the first closing element to close the wellbore around the drill pipe. The method further includes rotating a second drive shaft of the activation system, translating a second activation shaft of the activation system, the second activation shaft being coupled to the second drive shaft and to the second closing element, and pushing the second closing element into a second activated position against the drill pipe to close the wellbore around the drill pipe for preventing fluid from flowing out of the wellbore 
     In some embodiments, the closing element includes a pipe ram block. 
     In some embodiments, the activation system is a contingency activation system, and the fluid management system further includes a hydraulic activation system that is configured to move the closing element into the activated position against the drill pipe to close the wellbore around the drill pipe for preventing the fluid from flowing out of the wellbore. 
     In some embodiments, the method further includes determining a failure of the hydraulic activation system and operating the contingency activation system to move the closing element into the activated position against the drill pipe upon failure of the hydraulic activation system. 
     The details of one or more embodiments are set forth in the accompanying drawings and description. Other features, aspects, and advantages of the embodiments will become apparent from the description, drawings, and claims. 
    
    
     
       DESCRIPTION OF DRAWINGS 
         FIG. 1  is a top view of a portion of an example fluid management system in a deactivated state. 
         FIG. 2  is a top view of the portion of the fluid management system of  FIG. 1  in an activated state. 
         FIG. 3  is a top view of the fluid management system of  FIG. 1  in the deactivated state. 
         FIG. 4  is a top view of the fluid management system of  FIG. 1  in the activated state. 
         FIG. 5  is a flow chart illustrating an example method of controlling fluid flow at a wellbore using the fluid management system of  FIG. 1 . 
     
    
    
     DETAILED DESCRIPTION 
       FIGS. 1 and 2  illustrate a portion of a fluid management system  100  (for example, an annular blowout preventer) that is operable to close a wellbore  101  around a drill pipe  103  disposed within the wellbore  101 . In some instances, formation fluid within the wellbore  101  may begin to flow uncontrollably in an uphole direction around the drill pipe  103 , thereby posing the risk of a blowout of the wellbore  101 . The fluid management system  100  is designed to close against an exterior surface of the drill pipe  103  to prevent formation fluid within the wellbore  101  from spewing uncontrollably out of the wellbore  101  in such instances. In this manner, the fluid management system  100  is designed to isolate a pressure of the formation fluid within the wellbore  101  to prevent uncontrolled, uphole-directed fluid flow from the wellbore  101 . In some embodiments, the fluid management system  100  is an onshore blowout preventer positioned above ground and above a wellhead. In some embodiments, the fluid management system  100  is an offshore blowout preventer for a jack-up rig and positioned above a wellhead on a producing platform above sea level. 
     The fluid management system  100  includes two pipe ram blocks  102  (for example, blind ram blocks) that are formed to seal against the exterior surface of the drill pipe  103 , two rods  104  that extend respectively from the pipe ram blocks  102 , two pistons  106  that are carried respectively by the rods  104 , and a surrounding housing  108 . The fluid management system  100  is configured such that the rods  104  can be shifted linearly to move the pipe ram blocks  102  between an open, deactivated position (as shown in  FIG. 1 ) and a closed, activated position (as shown in  FIG. 2 ). The housing  108  includes an interior housing  110  that surrounds the pipe ram blocks  102  and an exterior housing  112  that, together with the interior housing  110 , forms two hydraulic fluid chambers  114  around the pistons  106 . Together, the interior and exterior housings  110 ,  112  also form an inner fluid channel  116  that fluidically communicates with inner regions  130  of the fluid chambers  114  and an outer fluid channel  118  that fluidically communicates with outer regions  132  of the fluid chambers  114 . The exterior housing  112  defines an opening fluid port  120  that is fluidically connected to the inner fluid channel  116  and a closing fluid port  122  that is fluidically connected to the outer fluid channel  118 . 
     The housings  110  and  112 , the fluid ports  120  and  122 , the fluid channels  118  and  120 , and the fluid chambers  114  together form a primary activation system  134  (for example, a hydraulic activation system) of the fluid management system  100  for closing the pipe ram blocks  102  against the drill pipe  103  to prevent formation fluid from flowing out of the wellbore  101  in an uphole direction. The primary activation system  134  is also operable to subsequently release the pipe ram blocks  102  from the drill pipe  103  to expose (for example, to open) the wellbore  101 . For example, according to one or more signals received from a control system  124 , hydraulic fluid can be delivered (refer to arrow  126 ) from a fluid receptacle  128  to the fluid port  122 , where such hydraulic fluid flows to the outer regions  132  of the fluid chambers  114  and pushes the pistons  106  inwardly, as shown in  FIG. 2 . The rods  104 , attached to the pistons  106 , force (for example, push) the pipe ram blocks  102  closed against the drill pipe  103  to isolate the wellbore  101 , while any hydraulic fluid that was present within the inner regions  130  of the fluid chambers  114  is forced out of the fluid chambers  114  through the inner fluid channel  116  and the opening fluid port  120  into a fluid receptacle  138 . 
     The primary activation system  134  is also operable, according to one or more signals received from the control system  124 , to release the pipe ram blocks  102  from the drill pipe  103 . For example, hydraulic fluid can be delivered (refer to arrow  136 ) from the fluid receptacle  138  to the fluid port  120 , where such hydraulic fluid flows to the inner regions  130  of the fluid chambers  114  and pushes the pistons  106  outwardly, as shown in  FIG. 1 . The rods  104 , attached to the pistons  106 , force (for example, pull) the pipe ram blocks  102  away from the drill pipe  103  to expose the wellbore  101 , while any hydraulic fluid that was present within the outer regions  132  of the fluid chambers  114  is forced out of the fluid chambers  114  through the outer fluid channel  118  and the closing fluid port  122  into the fluid receptacle  128 . 
     In case the primary activation system  134  of the fluid management system  100  fails to close the pipe ram blocks  102  against the drill pipe  103  for any reason, the fluid management system  100  further includes a secondary activation system  140  (for example, a mechanical activation system) that is operable as a backup, contingency measure to close the pipe ram blocks  102  against the drill pipe  103  to prevent formation fluid from flowing out of the wellbore  101  in an uphole direction. The secondary activation system  140  is also operable to subsequently release the pipe ram blocks  102  from the drill pipe  103  to expose the wellbore  101 . In some examples, the primary activation system  134  may fail due to a leak in one or both of the fluid channels  116 ,  118  or other hydraulic control lines. In some examples, the primary activation system  134  may fail due to a breakdown of one or more hydraulic control features. 
     In this regard, and referring to  FIGS. 3 and 4 , the fluid management system  100  further includes two activation shafts  142  that are respectively connected to outer ends of the rods  104  for translating the rods  104 , two drive shafts  144  that are coupled to the activation shafts  142  and rotatable to cause translation of the activation shafts  142  along the drive shafts  144 , two gears and drive loops  146  that are translatable respectively along the drive shafts  144  to rotate the drive shafts  144 , and two pneumatic motors  148  that are operable to activate rotation of the drive loops  146  for translation along the drive shafts  144 . In some embodiments, the drive loops  146  may be provided as drive belts. In some embodiments, the drive loops  146  may be provided as drive chains. 
     The drive shafts  144  have threaded exterior profiles  152  by which the drive loops  146  engage the drive shafts  144  to rotate the drive shafts  144 . The threaded exterior profiles  152  of the drive shafts  144  also engage respective threaded interior profiles  154  of the activation shafts  142  that causes the activation shafts  142  to translate as the drive shafts  144  rotate. In some embodiments, the exterior and interior threaded profiles  152 ,  154  are provided as square threads. Use of such square threads in the fluid management system  100  has several advantages over other forms of threads. For example, as compared to other types of threads, square threads have better transmission efficiency due to less friction, allow for high efficiency due to a profile angle of zero, transmit power without any side thrust in either direction, and are designed for power screw designs. The exterior housing  112  defines two channels  150  around the activation shafts  142  that respectively ensure smooth linear movements of the activation shafts  142  along the drive shafts  144 . 
     Rotation of the drive shafts  144  in a first rotational direction  156  results in inwardly directed translation of the activation shafts  142  to cause the pipe ram blocks  102  to close against each other around the drill pipe  103  to prevent formation fluid from flowing out of the wellbore  101 . In contrast, rotation of the drive shafts  144  in a second, opposite rotational direction  158  results in outwardly directed translation of the activation shafts  142  to cause the pipe ram blocks  102  to move away from each other and from the drill pipe  103 . For example, once the fluid flow of the wellbore  101  is put under control and the primary activation system  134  is repaired, the drive shafts  144  are rotated in the second rotational direction  158  to relieve the inwardly directed force from the pipe ram blocks  102  to allow the pipe ram blocks  102  to move back to the open position under hydraulic action of the primary activation system  134 . 
     In some embodiments, the difference (for example, a length of travel) between a fully deactivated position of an activation shaft  142  (as shown in  FIG. 3 ) and a fully activated position of the same activation shaft  142  (as shown in  FIG. 4 ) is a distance of about 0.09 meters (m) to about 0.27 m. In some embodiments, the activation shafts  142  and the drive shafts  144  are made of one or more materials, such as steel, that are resistant to corrosion, that can withstand high compressive loads, and that can withstand high torque loads. 
     The exterior housing  112 , the pneumatic motors  148 , the drive loops  146 , the drive shafts  144 , and the activation shafts  142  together form the secondary activation system  140  of the fluid management system  100  for closing the pipe ram blocks  102  against the drill pipe  103  to prevent formation fluid from flowing out of the wellbore  101  in an uncontrolled manner. The pneumatic motors  148  can be activated manually or according to one or more signals received from the control system  124  in a safe manner near the wellbore  101  without causing undesirable ignition of hydrocarbon oil or gas in the event of uncontrolled fluid flow or fluid leak. In some embodiments, components of the secondary activation system  140  may be installed to a fluid management system that is substantially similar in construction and function to the fluid management system  100 , but that does not initially include any contingency well closure mechanism. 
       FIG. 5  is a flow chart illustrating an example method  200  of controlling fluid flow at a wellbore (for example, the wellbore  101 ). In some embodiments, the method  200  includes providing a closing element (for example, a pipe ram block  102 ) of a fluid management system (for example, the fluid management system  100 ) at the wellbore, the closing element being formed complementary to a drill pipe (for example, the drill pipe  103 ) disposed within the wellbore ( 202 ). In some embodiments, the method  200  further includes rotating a drive shaft (for example, the drive shaft  144 ) of an activation system (for example, the secondary activation system  140 ) of the fluid management system ( 204 ). In some embodiments, the method  200  further includes translating an activation shaft (for example, the activation shaft  142 ) of the activation system, the activation shaft being coupled to the drive shaft and to the closing element ( 206 ). In some embodiments, the method  200  further includes pushing the closing element into an activated position against the drill pipe to close the wellbore around the drill pipe for preventing fluid from flowing out of the wellbore ( 208 ). 
     While the fluid management system  100  has been described and illustrated with respect to certain dimensions, sizes, shapes, arrangements, materials, and methods  200 , in some embodiments, a fluid management system that is otherwise substantially similar in construction and function to the fluid management system  100  may include one or more different dimensions, sizes, shapes, arrangements, and materials or may be utilized according to different methods. 
     Accordingly, other embodiments are also within the scope of the following claims.