Patent Publication Number: US-11377917-B2

Title: Staged annular restriction for managed pressure drilling

Description:
This application claims the benefit of and priority to a US Provisional Application having Ser. No. 62/437,850, filed 22 Dec. 2016, which is incorporated by reference herein. 
    
    
     BACKGROUND 
     The disclosure relates generally to the field of “managed pressure” wellbore drilling. More specifically, the disclosure relates to managed pressure control apparatus and methods which do not require the use of a rotating control device (“RCD”), rotating blowout preventer or similar apparatus to restrict or close a wellbore annulus. 
     Managed pressure drilling uses well pressure control systems that control return flow of drilling fluid in a wellbore annulus to maintain a selected pressure or pressure profile in a wellbore. U.S. Pat. No. 6,904,981 issued to van Riet describes one such system for controlling wellbore pressure during the drilling of a wellbore through subterranean formations. The system described in the &#39;981 patent includes a drill string extending into the wellbore. The drill string may include a bottom hole assembly (“BHA”) including a drill bit, drill collars, sensors (which may be disposed in one or more of the drill collars), and a telemetry system capable of receiving and transmitting sensor data between the BHA and a control system disposed at the surface. Sensors disposed in the bottom hole assembly may include pressure and temperature sensors. The control system may comprise a telemetry system for receiving telemetry signals from the sensors and for transmitting commands and data to certain components in the BHA. 
     A drilling fluid (“mud”) pump or pumps may selectively pump drilling fluid from a drilling fluid reservoir, through the drill string, out from the drill bit at the end of the drill string and into an annular space created as the drill string penetrates the subsurface formations. A fluid discharge conduit is in fluid communication with the annular space for discharging the drilling fluid to the reservoir to clean the drilling fluid for reuse. A fluid back pressure system is connected to the fluid discharge conduit. The fluid back pressure system may include a flow meter, a controllable orifice fluid choke, a back pressure pump and a fluid source coupled to the pump intake. The back pressure pump may be selectively activated to increase annular space drilling fluid pressure. Other examples may exclude the back pressure pump. 
     Systems such as those described in the van Riet &#39;981 patent comprise a RCD or similar rotatable sealing element at a selected position, in some implementations at or near the upper end of the wellbore. The upper end of the wellbore may be a surface casing extending into the subsurface and cemented in place, or in the case of marine wellbore drilling, may comprise a conduit called a “riser” that extends from a wellhead disposed on the water bottom and extending to a drilling platform proximate the water surface. Further, in such systems as described in the van Riet &#39;981 patent, a fluid discharge line from the upper end of the wellbore but below the RCD may comprise devices such as a controllable orifice choke such that drilling fluid returning from the wellbore may have its flow controllably restricted to provide a selected fluid pressure in the wellbore or a selected fluid pressure profile (i.e., fluid pressure with respect to depth in the wellbore). 
       FIG. 1  shows an example of a well drilling system  100  that uses a rotating control device (RCD) to close fluid discharge from a subsurface wellbore so that it is constrained to flow through a controllable orifice choke. Using the controllable orifice choke and measurements from certain sensors, explained below, a selected fluid pressure or fluid pressure profile may be maintained in the wellbore. While the present example embodiment and an embodiment according to the disclosure described with reference to  FIG. 2 , are described with reference to drilling a well below the bottom of the land surface, methods and apparatus according to the present disclosure may also be used with apparatus and methods for drilling into formations below the bottom of a body of water. 
     The well drilling system may make use of a managed pressure drilling (MPD) system during drilling of a wellbore to adjust the fluid pressure in a wellbore annulus to selected values during drilling. Operation and details of the MPD system may be substantially as described in U.S. Pat. No. 7,395,878 issued to Reitsma et al. and in U.S. Pat. No. 6,904,981 issued to van Riet. 
     The well drilling system  100  includes a hoisting device known as a drilling rig  102  that is used to support drilling a wellbore through subsurface rock formations such as shown at  104 . Many of the components used on the drilling rig  102 , such as a kelly (or top drive), power tongs, slips, draw works and other equipment are not shown for clarity of the illustration. A wellbore  106  is shown being drilled through the rock formations  104 . A drill string  112  is suspended from the drilling rig  102  and extends into the wellbore  106 , thereby forming an annular space (annulus)  115  between the wellbore  106  wall and the drill string  112 , and/or between a casing  101  and the drill string  112 . The drill string  112  is used to convey a drilling fluid  150  (shown in a storage tank or pit  136  to the bottom of the wellbore  106  and into the wellbore annulus  115 . 
     The drill string  112  may support a bottom hole assembly (BHA)  113  proximate the lower end thereof that includes a drill bit  120 , and may include a mud motor  118 , a sensor package  119 , a check valve (not shown) to prevent backflow of drilling fluid from the annulus  115  into the drill string  112 . The sensor package  119  may be, for example, a measurement while drilling and logging while drilling (MWD/LWD) sensor system. In particular the BHA  113  may include a pressure transducer  116  to measure the pressure of the drilling fluid in the annulus at the depth of the pressure transducer  116 . The BHA  113  shown in  FIG. 1  may also include a telemetry transmitter  122  that can be used to transmit pressure measurements made by the transducer  116 , MWD/LWD measurements as well as drilling information to be received at the surface. A data memory including a pressure data memory may be provided at a convenient place in the BHA  113  for temporary storage of measured pressure and other data (e.g., MWD/LWD data) before transmission of the data using the telemetry transmitter  122 . The telemetry transmitter  122  may be, for example, a controllable valve that modulates flow of the drilling fluid through the drill string  112  to create pressure changes in the drilling fluid  150  that are detectable at the surface. The pressure changes may be coded to represent signals from the MWD/LWD system (sensor package  119 ) and the pressure transducer  116 . 
     The drilling fluid  150  may be stored in a reservoir  136 , which is shown in the form of a mud tank or pit. The reservoir  136  is in fluid communications with the intake of one or more mud pumps  138  that in operation pump the drilling fluid  150  through a conduit  140 . A flow meter  152  may be provided in series with one or more mud pumps  138 . The conduit  140  is connected to suitable pressure sealed swivels (not shown) coupled to the uppermost segment (“joint”) of the drill string  112 . During operation, the drilling fluid  150  is lifted from the reservoir  136  by the pumps  138 , is pumped through the drill string  112  and the BHA  113  and exits the through nozzles or courses (not shown) in the drill bit  120 , where it circulates the cuttings away from the bit  120  and returns them to the surface through the annulus  115 . The drilling fluid  150  returns to the surface and passes through a drilling fluid discharge conduit  124  and in some embodiments through various surge tanks and telemetry receiver (e.g., a pressure sensor—not shown) to be returned, ultimately, to the reservoir  136 . 
     A pressure isolating seal for the annulus  115  is provided in the form of a rotating control device (RCD) mounted above a blowout preventer (“BOP”)  142 . The drill string  112  passes through the BOP  142  and its associated RCD. When actuated, the RCD seals around the drill string  112 , isolating the fluid pressure therebelow, but still enables drill string rotation and longitudinal movement. Alternatively a rotating BOP (not shown) may be used for essentially the same purpose. The pressure isolating seal forms a part of a back pressure system used to maintain a selected fluid pressure in the annulus  115 . 
     As the drilling fluid returns to the surface it passes through a side outlet below the RCD to a back pressure system  131  configured to provide an adjustable back pressure on the drilling fluid in the annulus  115 . The back pressure system  131  comprises a variable flow restriction device, in some embodiments in the form of a controllable orifice choke  130 . It will be appreciated that there exist chokes designed to operate in an environment where the drilling fluid  150  contains substantial drill cuttings and other solids. The controllable orifice choke  130  may one type of a variable flow restriction device and is further capable of operating at variable pressures, flow rates and through multiple duty cycles. 
     The drilling fluid  150  exits the controllable orifice choke  130  and flows through a flow meter  126 , which may then be directed through a optional degasser  1  and solids separation equipment  129 . The degasser  1  and solids separation equipment  129  are designed to remove excess gas and other contaminants, including drill cuttings, from the returning drilling fluid  150 . After passing through the degasser  1  and solids separation equipment  129 , the drilling fluid  150  is returned to reservoir  136 . In the present example, the drilling fluid reservoir  136  comprises a trip tank  2  in addition to the mud tank or pit  136 . A trip tank may be used on a drilling rig to monitor drilling fluid gains and losses during movement of the drill string into and out of the wellbore  106  (known as “tripping operations”). 
     Various valves  5 ,  125  and lines  4 ,  119 ,  119 A,  119 B may be provided to operate the back pressure system  131  if and as needed. 
     The flow meter  126  may be a mass-balance type, Coriolis-type or other high-resolution flow meter. A pressure sensor  147  may be provided in the drilling fluid discharge conduit  124  upstream of the variable flow restrictor (e.g., the controllable orifice choke  130 ). A second flow meter, similar to flow meter  126 , may be placed upstream of the RCD in addition to the pressure sensor  147 . The back pressure system  131  may comprise a control system  146  for monitoring measurements from the foregoing sensors (e.g., flow meters  126  and  152  and pressure transducer  147 ). The control system  146  may provide operating signals to selectively control To enable data relevant for the annulus pressure, and providing control signals to at least a back pressure system  131  and in some embodiments to the mud pumps  138 . 
     The back pressure system  131  may comprise the controllable orifice choke  130 , flow meter  126  and a secondary pump  128 . Signals from the above described sensors may be conducted to a control unit  146 . Control signals from the control unit  146  may be conducted to the mud pump(s)  138 , the secondary pump  128  and the controllable orifice choke  130  During operation of the drilling system, if the drilling fluid pump  138  is operating, the back pressure system  131  may provide a selected pressure in the annulus  115  by operating the controllable orifice choke  130  to restrict the flow of drilling fluid  150  leaving the annulus  115 . During times when the drilling fluid pump  138  is not operating, the secondary pump  128  may provide drilling fluid under pressure to the annulus  115  to maintain the selected fluid pressure. 
     In some embodiments, a selected fluid pressure may be applied to the annulus  115  to maintain the desired annulus in the wellbore  106  by obtaining, at selected times, measurements related to the existing pressure of the drilling fluid in the annulus  115  in the vicinity of the BHA  113  using the pressure transudcer  116  or similar pressure sensor. Such pressure measurement may be referred to as the bottom hole pressure (BHP). Differences between the determined BHP and the desired BHP may be used for determining a set-point back pressure. The set point back pressure is used for controlling the back pressure system  131  in order to establish a back pressure close to the set-point back pressure. Information concerning the fluid pressure in the annulus  115  proximate the BHA  113  may be determined using an hydraulic model and measurements of drilling fluid pressure as it is pumped into the drill string and the rate at which the drilling fluid is pumped into the drill string (e.g., using a flow meter or a “stroke counter” typically provided with piston type mud pumps). The BHP information thus obtained may be periodically checked and/or calibrated using measurements made by the pressure transducer  116 . 
     In other embodiments, an injection fluid supply  143  which may comprise a storage tank and one or more injection pumps (not shown separately) may use a pressure measurement generated by an injection fluid pressure sensor anywhere in the injection fluid supply passage, e.g., at  156 , may be used to provide an input signal for controlling the back pressure system  131 , and thereby for monitoring the drilling fluid pressure in the wellbore annulus  115 . 
     The pressure signal may, if so desired, be compensated for the density of the injection fluid column and/or for the dynamic pressure loss that may be generated in the injection fluid between the injection fluid pressure sensor in the injection fluid supply passage and where the injection into the drilling fluid return passage takes place, for instance, in order to obtain an exact value of the injection pressure in the drilling fluid return passage at the depth where the injection fluid is injected into the drilling fluid gap. 
     The described existing MPD system is effective, however there are limitations inherent to the use of RCDs in controlling fluid leaving a wellbore. It is desirable to provide control of fluid pressure in a wellbore (i.e., annulus) without the need to use RCDs or similar rotating pressure control devices at the upper end of the well. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  shows an example embodiment of a drilling system including a well pressure control apparatus. 
         FIG. 2  shows an example embodiment of a drilling system including a well outflow control according to the present disclosure used in connection a well pressure control apparatus. 
         FIG. 3  shows a detailed view of one example embodiment of a well outflow control. 
     
    
    
     DETAILED DESCRIPTION 
     An example embodiment of a well drilling system  100  that may be used with a well fluid discharge control may be better understood with reference to  FIG. 2 . The well drilling system  100  may comprise many of the same components described with reference to the well drilling system shown in  FIG. 1  and described above. 
     Components of the example embodiment of the well drilling system in  FIG. 2  may omit the backpressure system  131  and the components therein, including, for example the variable orifice choke ( 130  in  FIG. 1 ), the secondary pump  128 , and external to the backpressure system  131 , valves  5 ,  125  lines  4 ,  119 A and  119 B. The RCD at the upper end of the BOP  142  may also be omitted. Flow out of the annulus  115  may be controlled by a well outflow control  135  disposed in the well casing  101 , above a BOP stack (not shown in  FIG. 2 ). The well casing  101  may comprise a fluid discharge line  124  connected to the wellbore  106  above the well outflow control  135 , such that the fluid actually discharged from the wellbore  106  may be at atmospheric pressure, and the wellbore  106  may not need a rotating sealing element such as a RCD (as shown in  FIG. 1 ). 
     The well outflow control  135  will be further explained below with reference to  FIG. 3 . In the present example embodiment of a well drilling system, pressure in the annulus  115  may be maintained by communicating to the control system  146  signals from the flow meter  152 , pressure transducer  116 , pressure sensor  147  and in some embodiments a second flow meter  126  disposed in the fluid discharge line  124 . Control signals from the control system  146  may operate the well outflow control  135  and the mud pump(s)  138  to maintain a selected fluid pressure in the annulus  115 . The selected fluid pressure may be calculated substantially as explained above with reference to  FIG. 1  and in a manner similar to operation of a controllable choke as disclosed in U.S. Pat. No. 6,904,891 issued to van Riet, incorporated herein by reference in its entirety. When the mud pump(s) are switched off, such as during adding a segment of dill pipe to the drill string  112  or removing a segment therefrom, pressure in the annulus  115  may be maintained using the fluid injection system comprising the injection fluid supply  143  which may comprise a storage tank and one or more injection pumps (not shown separately) and the pressure measurement generated by the injection fluid pressure sensor disposed anywhere in the injection fluid supply passage, e.g., at  156 . 
     One example embodiment of a well outflow control is shown schematically in  FIG. 3 . The well outflow control  135  may comprise a housing  101 A, which may be a segment of well casing, e.g., shown at  101  in  FIG. 2  or a segment of drilling riser (not shown) for marine drilling applications. The present example embodiment of the well outflow control  135  may include a plurality of, in the present example embodiment three, inwardly expandable, annular flow restrictors  11 A,  11 B,  11 C. The annular flow restrictors  11 A,  11 B,  11 C may be coupled to or affixed to an interior of the housing  101 A at selected longitudinal positions along the interior of the housing  101 A. In some embodiments more or fewer annular flow restrictors may be used. A minimum number of the annular flow restrictors  11 A,  11 B  11 C may be two. In the present example embodiment, the annular flow restrictors  11 A,  11 B,  11 C may each comprise a controllable inner diameter restrictor element, shown at  10 ,  12  and  14 , respectively. In some embodiments, the restrictor elements  10 ,  12 ,  14  may each comprise an inflatable elastomer bladder. 
     Each annular flow restrictor  11 A,  11 B,  11 C may comprise a respective actuator and sensor, shown at  10 A/ 10 B,  12 A/ 12 B and  14 A/ 14 B, as a single element in  FIG. 3  for clarity of the drawing. In one embodiment actuator  10 A,  12 A, may comprise a line (not shown) coupled to the outlet of a pump (e.g., part of  143  in  FIG. 2 )), whereby fluid pumped into a space within the restrictor element  10 ,  12 ,  14  causes the restrictor element  10 ,  12 ,  14  to inflate and correspondingly reduce the cross-sectional area of a space between the exterior of the drill string  112  and the inner diameter of each inflated restrictor element  10 ,  12 ,  14 . In the present example embodiment, an amount of inflation may be determined from measurements made by the respective sensors  10 B,  12 B,  14 B. In some embodiments, the sensors  10 B,  12 B,  14 B may comprise pressure sensors, whereby an amount of closure of each restrictor element may be inferred from the pressure measured by each sensor  10 B,  12 B,  14 B. In some embodiments the sensors  10 B,  12 B,  14 B may comprise linear position sensors, for example, linear variable differential transformers (LVDTs). In some embodiments, the actuators  10 A,  12 A,  14 A may comprise linear actuators. See, for example, U.S. Pat. No. 7,675,253 issued to Dorel. In some embodiments, one or more of the restrictor elements  10 ,  12 ,  14  may comprise an “iris” type valve. See, for example, U.S. Pat. No. 7,021,604 issued to Werner et al. 
     Regardless of the type of actuator used, functionally, each actuator  10 A,  12 A,  14 A when operated causes the respective restrictor element  10 ,  12 ,  14  to close to a selected inner diameter. In the present embodiment, the lowermost restrictor element  14  is closed to the largest inner diameter. The middle restrictor element  12  may be closed to an inner diameter intermediate to the closed inner diameter of the lowermost restrictor element  14  and the uppermost restrictor element  10 . The uppermost restrictor element  10  thus may be closed to the smallest inner diameter. Each sensor  10 B,  12 B,  14 C is in signal communication with the control unit ( 146  in  FIG. 2 ) such that the amount by which each annular flow restrictor  11 A,  11 B,  11 C is closed may be determined and used by the control unit ( 146  in  FIG. 2 ) to cause operation of each actuator  10 A,  12 A,  14 A to close the respective annular flow restrictor  11 A,  11 B,  11 C to an amount such that fluid in the wellbore ( 112  in  FIG. 2 ) is maintained at a selected pressure, or provides a selected pressure profile along the wellbore ( 112  in  FIG. 2 ). 
     Opening and closing the annular flow restrictors  11 A,  11 B,  11 C may be controlled in a manner similar to operating a variable orifice choke as explained in the Background section herein. In some embodiments, the amount of closure of each of the annular flow restrictors  11 A,  11 B,  11 C in the aggregate may enable maintain the wellbore pressure at a selected set point pressure, for example, as described in the van Riet &#39;891 patent referred to above. Using multiple annular flow restrictors  11 A,  11 B,  11 C closed to successively smaller inner diameters along the direction of returning drilling fluid  138  moving upwardly through the housing  101 A reduces the pressure of the returning drilling fluid  138  in stages in order to reduce drill string wear resulting from increased velocity of the drilling fluid  138 . The increase in velocity is related to the reduction in diameter of the annular space between the outside of the drill string  112  and the inner surface of each annular flow restrictor  11 A,  11 B,  11 C. 
     The present example embodiment provides that the restrictor elements  10 ,  12 ,  14  when fully inflated (or closed to a smallest inner diameter) do not actually contact the drill string  112 . There is, however, the possibility of incidental wear if the drill string  112  is off center. The restrictor elements  10 ,  12 ,  14  in some embodiments may comprise wear plates  10 C,  12 C,  14 C formed into or affixed to the interior surface of each restrictor element  10 ,  12 ,  14 , respectively to reduce wear by incidental contact with the drill string  112 . Such wear plates  10 C,  12 C,  14 C may be made from steel or other wear resistant material. 
     A well fluid outflow control according to the various aspects of the present disclosure may enable performing managed pressure drilling (MPD) without the need to use a rotating control device or similar rotating sealing element. Such capability may reduce the time and expense of repair and maintenance of rotating control devices. 
     While the present disclosure describes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of what has been disclosed herein. Accordingly, the scope of the disclosure should be limited only by the attached claims.