Staged annular restriction for managed pressure drilling

Abstract

An apparatus includes a conduit forming part of a drilling fluid return path from a wellbore. The the conduit has at least one well outflow control in the conduit. The at least one well fluid outflow control has at least two annular flow restrictors each separately operable to close to a respective inner diameter.

Claims

1. A system, comprising: a drill string extending into a wellbore drilled through subsurface formations; a pump having an inlet in fluid communication with a supply of drilling fluid, the pump having an outlet in fluid communication with an interior of the drill string; a conduit extending from a first position in the wellbore to a second position proximate a surface end of the wellbore, wherein the pumped drilling fluid is configured to be returned upwardly through an annular space between an exterior of the drill string and an interior of the conduit; at least one well fluid outflow control comprising a housing disposed along the conduit and at least two annular flow restrictors disposed at distinct axial positions within the housing; and a control system configured to generate control signals to cause the at least two annular flow restrictors to close to provide successively smaller inner diameters in a direction of the drilling fluid moving upwardly through the annular space.

2. The system of claim 1 wherein each of the at least two annular flow restrictors comprises an inflatable restrictor element.

3. The system of claim 2 wherein each inflatable restrictor element comprises a linear position sensor arranged to measure an amount of closure of the respective inflatable restrictor element.

4. The system of claim 2 wherein each inflatable restrictor element comprises a pressure sensor operable to measure a fluid pressure inside the respective inflatable restrictor element.

5. The system of claim 2 wherein each inflatable restrictor element comprises a wear plate on an interior surface thereof.

6. The system of claim 1 wherein each of the at least two annular flow restrictors comprises an iris valve.

7. The system of claim 1 wherein each of the at least two annular flow restrictors comprises a linear actuator operable to close a restrictor element on the respective annular flow restrictor.

8. The system of claim 1 further comprising a pressure sensor arranged to measure pressure of the drilling fluid in the annular space between the drill string and the conduit at a position below the at least one well fluid outflow control.

9. The system of claim 1 further comprising at least one flow meter arranged to measure a first rate of flow of the drilling fluid into the drill string from the pump, and at least one flow meter arranged to measure a second rate of flow of the drilling fluid out of the conduit.

10. The system of claim 1 further comprising a pressure sensor arranged to measure pressure of the drilling fluid at an inlet to the interior of the drill string.

11. The system of claim 1 wherein the conduit comprises a casing in the wellbore.

12. A method, comprising: pumping drilling fluid through a drill string extended into a wellbore drilled through subsurface formations; returning the pumped drilling fluid upwardly through an annular space between an exterior of the drill string and an interior of a conduit disposed to a selected depth in the wellbore; and selectively restricting outflow of fluid from the interior of the conduit by operating at least one well fluid outflow control comprising a housing disposed along the conduit and at least two annular flow restrictors disposed at distinct axial positions within the housing, wherein operating the at least one well fluid outflow control comprises generating control signals to instruct the at least two annular flow restrictors to close to provide successively smaller inner diameters in a direction of the drilling fluid moving upwardly through the annular space.

13. The method of claim 12 further comprising measuring a pressure of the drilling fluid in the conduit below the at least one well fluid outflow control, and automatically operating the at least one well fluid outflow control to close the at least two annular flow restrictors to the successively smaller inner diameters to maintain a selected pressure in the wellbore.

14. The method of claim 12 further comprising measuring a pressure of the drilling fluid entering an interior of the drill string and measuring a flow rate of the drilling fluid entering the interior of the drill string or a flow rate of the drilling fluid exiting the conduit, and automatically operating the at least one well fluid outflow control to close the at least two annular flow restrictors to the successively smaller inner diameters to maintain a selected measured pressure and measured flow rate.

15. An apparatus, comprising: a conduit forming part of a drilling fluid return path from a wellbore, the conduit comprising at least one well outflow control in the conduit; wherein the at least one well fluid outflow control comprises at least two annular flow restrictors disposed at distinct axial positions in the conduit and that are separately operable to close to provide successively smaller inner diameters in a direction of the drilling fluid moving upwardly in the return path from the wellbore.

16. The apparatus of claim 15 wherein each of the at least two annular flow restrictors comprises an inflatable restrictor element.

17. The apparatus of claim 16 wherein each inflatable restrictor element comprises a sensor arranged to measure an amount of closure of the respective inflatable restrictor element.

18. The apparatus of claim 16 wherein each inflatable restrictor element comprises a pressure sensor operable to measure a fluid pressure inside the respective inflatable restrictor element.

19. The apparatus of claim 15, comprising a control system configured to generate control signals to instruct the at least two annular flow restrictors to close to provide the successively smaller inner diameters.

20. The apparatus of claim 15, wherein none of the at least two annular flow restrictors are configured to form an annular seal about an exterior of a drill string extending through the conduit while the at least two annular flow restrictors are closed to provide the successively smaller inner diameters.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 shows an example embodiment of a drilling system including a well pressure control apparatus.

(2) 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.

(3) FIG. 3 shows a detailed view of one example embodiment of a well outflow control.

DETAILED DESCRIPTION

(4) 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.

(5) 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, 119A and 119B. 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).

(6) 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.

(7) One example embodiment of a well outflow control is shown schematically in FIG. 3. The well outflow control 135 may comprise a housing 101A, 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 11A, 11B, 11C. The annular flow restrictors 11A, 11B, 11C may be coupled to or affixed to an interior of the housing 101A at selected longitudinal positions along the interior of the housing 101A. In some embodiments more or fewer annular flow restrictors may be used. A minimum number of the annular flow restrictors 11A, 11B 11C may be two. In the present example embodiment, the annular flow restrictors 11A, 11B, 11C 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.

(8) Each annular flow restrictor 11A, 11B, 11C may comprise a respective actuator and sensor, shown at 10A/10B, 12A/12B and 14A/14B, as a single element in FIG. 3 for clarity of the drawing. In one embodiment actuator 10A, 12A, 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 10B, 12B, 14B. In some embodiments, the sensors 10B, 12B, 14B may comprise pressure sensors, whereby an amount of closure of each restrictor element may be inferred from the pressure measured by each sensor 10B, 12B, 14B. In some embodiments the sensors 10B, 12B, 14B may comprise linear position sensors, for example, linear variable differential transformers (LVDTs). In some embodiments, the actuators 10A, 12A, 14A 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.

(9) Regardless of the type of actuator used, functionally, each actuator 10A, 12A, 14A 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 10B, 12B, 14C is in signal communication with the control unit (146 in FIG. 2) such that the amount by which each annular flow restrictor 11A, 11B, 11C is closed may be determined and used by the control unit (146 in FIG. 2) to cause operation of each actuator 10A, 12A, 14A to close the respective annular flow restrictor 11A, 11B, 11C 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).

(10) Opening and closing the annular flow restrictors 11A, 11B, 11C 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 11A, 11B, 11C in the aggregate may enable maintain the wellbore pressure at a selected set point pressure, for example, as described in the van Riet '891 patent referred to above. Using multiple annular flow restrictors 11A, 11B, 11C closed to successively smaller inner diameters along the direction of returning drilling fluid 138 moving upwardly through the housing 101A 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 11A, 11B, 11C.

(11) 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 10C, 12C, 14C 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 10C, 12C, 14C may be made from steel or other wear resistant material.

(12) 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.

(13) 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.