Apparatus, System, and Method for Controlling the Flow of Drilling Fluid in a Wellbore

Abstract

A drilling system includes a drill string extending through a BOP and a drilling fluid discharge coupling mounted to the BOP. In addition, the drilling system includes a drilling fluid control system configured to control a pressure or flow rate of a drilling fluid flowing through the discharge coupling. The drilling fluid control system includes a flow rate and pressure regulating device, a feedback controller system configured to operate the regulating device, and a first sensor configured to measure an actual pressure or flow rate of the drilling fluid flowing through the discharge coupling.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional patent application Ser. No. 61/708,881 filed Oct. 2, 2012, and entitled “Apparatus, System, and Method for Controlling the Flow of Drilling Fluid in a Wellbore,” which is hereby incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The present disclosure relates generally to apparatus, systems, and methods for controlling the flow of drilling fluid. More particularly, the disclosure relates to systems and methods for managing the pressure in a borehole by controlling the discharge of drilling fluid from the borehole as is performed, for example, during managed pressure drilling (MPD).

During the drilling of exploratory wells and the drilling and completing of oil and gas wells, drilling fluid, also called drilling mud, is pumped into the well to maintain a desired pressure within the borehole. Managing the pressure in the well is necessary to inhibit or reduce the influx of formation fluids into the wellbore, while ensuring excessive wellbore pressure does not fracture the formation and lead to significant drilling fluid loss into the formation. Managed Pressure Drilling (MPD) is a drilling process in which the annular pressure profile in the borehole is controlled. MPD helps manage and mitigate potential problems associated with drilling of fractured or karstic carbonate reservoirs, well bore instability, differentially stuck pipe, and drilling formations with a tight margin between formation fracturing pressure and pore pressure.

During conventional MPD operations, pressurized drilling fluid is pumped down the drill string that supports the drill bit and other downhole tools. The fluid discharges through nozzles in the drill bit. The drilling fluid then travels upward through the annulus located between the drill string and the borehole wall to the surface. The drilling mud in the annulus contacts the formation, thereby exerting pressure against the formation. The fluid exits the top of the borehole through a back-pressure device, which influences the pressure and flow rate of drilling fluid through the annulus. Within the borehole, fluid pressure is managed by the adjusting the density, and hence weight, of the drilling fluid to control the hydrostatic pressure, by adjusting the pressure supplied by the mud pump, and by regulating the restriction induced by the back-pressure device. When the pressure in the borehole moves outside a target pressure range, an adjustment is often made at the back-pressure device to steer the borehole pressure back into the target range. Reaching a value within the target pressure using conventional techniques typically requires repeated, iterative adjustments, which often result in an undesirable relatively slow response and/or undesirable over-shooting of the target range.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by a drilling system for forming a borehole in an earthen formation. In an embodiment, the drilling system includes a drill string extending through a blowout preventer, and a drilling fluid discharge coupling mounted to the blowout preventer. In addition; the drilling system includes a drilling fluid control system configured to control a pressure or flow rate of a drilling fluid flowing through the discharge coupling. Further, the drilling fluid control system includes a flow rate and pressure regulating device, a feedback controller system configured to operate the regulating device, and a first sensor configured to measure an actual pressure or flow rate of the drilling fluid flowing through the discharge coupling. The regulating device includes a drilling fluid inlet in fluid communication with the discharge coupling, a drilling fluid outlet, an annular cage positioned between the inlet and the outlet, a valve plug slidingly disposed within the cage, an actuator, and a second sensor. The actuator is configured to adjust an axial position of the valve plug relative to the cage to selectively control the flow of drilling fluid through the cage from the inlet to the outlet, and the second sensor is configured to measure an actual axial position of the valve plug relative to the cage. Still further, the feedback controller system is configured to receive a desired pressure or flow rate and includes a process control engine configured to adjust the axial position of the valve plug relative to the cage based on a comparison of the actual pressure or flow rate measured by the first sensor and the desired pressure or flow rate and based on a comparison of the actual change in the axial position of the valve plug relative to the cage measured by the second sensor and a desired change in the axial position.

These and other needs in the art are addressed in another embodiment by a method for controlling the pressure or flow rate of drilling fluid flowing from a borehole through a valve. In an embodiment, the method includes (a) measuring the pressure or flow rate of the drilling fluid. In addition, the method includes (b) obtaining a desired pressure or flow rate for the drilling fluid. Further, the method includes, comparing the measured pressure or flow rate with the desired pressure or flow rate. Still further, the method includes (d) determining a desired change in an axial position of a valve plug within the valve based on the comparison in (c). In addition, the method includes (e) adjusting the axial position of the valve plug based on the desired change in the axial position of the valve plug in (d). Continuing, the method includes (f) determining an actual change in the axial position of the valve plug during (e). The method also includes (g) comparing the actual change in the axial position of the valve plug with the desired change in the axial position of the valve plug during (e).

These and other needs in the art are addressed in another embodiment by a method for controlling the pressure or flow rate of drilling fluid flowing from a borehole through a flow rate and pressure regulating device. In an embodiment, the method includes utilizing a first control loop to determine a desired change in a position of a valve plug within the regulating device to achieve a desired pressure or flow rate of the drilling fluid. In addition, the method includes utilizing a second control loop to adjust the actual position of the valve plug within the regulating device based on the desired change in the position of the valve plug from the first control loop.

Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the disclosed embodiments of the disclosure, reference will now be made to the accompanying drawings in which

FIG. 1 is a schematic, partial cross-sectional view of an embodiment of a system for drilling a borehole in accordance with principles disclosed herein;

FIG. 2 is an enlarged schematic view of the drilling fluid flow rate and pressure control system of FIG. 1;

FIG. 3 is an enlarged perspective view of the flow rate and pressure regulating device of FIG. 2;

FIG. 4 is a perspective, cross-sectional view of the flow rate and pressure regulating device of FIG. 3;

FIG. 5 is a perspective, cross-sectional view of the flow and pressure control assembly of FIG. 3;

FIG. 6 is a schematic view of the drilling fluid flow rate and pressure control system of FIG. 1;

FIG. 7 is a schematic view of a control system logic diagram for the drilling fluid flow rate and pressure control system of FIGS. 1 and 6;

FIG. 8 is a schematic view of the user interface of the drilling fluid flow rate and pressure control system of FIG. 7;

FIG. 9 is a perspective view of an embodiment of a flow rate and pressure regulating device in accordance with principles disclosed herein; and

FIG. 10 is a partial cross-sectional view of the flow rate and pressure regulating device of FIG. 9 in an open position allowing fluid flow therethrough.

DETAILED DESCRIPTION OF THE DISCLOSED EMBODIMENTS

The following description is exemplary of embodiments of the disclosure. These embodiments are not to be interpreted or otherwise used as limiting the scope of the disclosure, including the claims. One skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and is not intended to suggest in any way that the scope of the disclosure, including the claims, is limited to that embodiment.

The drawing figures are not necessarily to scale. Certain features and components disclosed herein may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness. In some of the figures, one or more components or aspects of a component may be not displayed or may not have reference numerals identifying the features or components that are identified elsewhere in order to improve clarity and conciseness of the figure.

The terms “including” and “comprising” are used herein, including in the claims, in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first component couples or is coupled to a second component, the connection between the components may be through a direct engagement of the two components, or through an indirect connection that is accomplished via other intermediate components, devices and/or connections. In addition, if the connection transfers electrical power or signals, whether analog or digital for example, the coupling may comprise wires or a mode of wireless electromagnetic transmission such as radio frequency, microwave, optical, or another mode. So too, the coupling may comprise a magnetic coupling or any other mode of transfer known in the art, or the coupling may comprise a combination of any of these modes. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a given axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the axis. For instance, an axial distance refers to a distance measured along or parallel to the axis, and a radial distance means a distance measured perpendicular to the axis. Any reference to up or down in the description and the claims will be made for purpose of clarification, with “up,” “upper,” “upwardly,” or “upstream” meaning toward the surface of the well and with “down,” “lower,” “downwardly,” or “downstream” meaning toward the terminal end of the well, regardless of the well bore orientation. In some applications of the technology, the orientations of the components with respect to the surroundings may be different. For example, components described as facing “up,” may alternately face to the left, may face down, or may face in another direction in another instance or in one or more other embodiments. The recitation “based on” means “based at least in part on.” Therefore, if X is based on Y, X may be based on Y and any number of other factors.

Disclosed herein are embodiments of systems and methods for controlling the flow rate and pressure of drilling fluid within a wellbore. The systems and methods described herein are particularly suited for managed pressure drilling (MPD), but can be used in other types of drilling operations. It should be appreciated that the drilling fluid flowing through the annulus to the surface may include some formation fluids. In at least some embodiments, the equipment and control scheme are configured to achieve a mathematically linear or more-nearly mathematically linear relationship or response between the movement of an actuator in a valve (e.g. the movement of a control choke or the movement of valve plug relative to a valve seat) and the resulting change in pressure in the wellbore or the change in flow rate of the drilling fluid exiting the wellbore. However, depending on the design of the actuator in the valve, the movements of the actuator in the valve can be rectilinear in various embodiments. For example, in some embodiments, the valve actuator can rotate so that changes in pressure or flow rate are related to angular displacements of the actuator or are related to a combined angular and linear displacement of the actuator in the valve. Still further, the systems and methods described herein provide a means for quickly adjusting the drilling fluid exit flow path to compensate for changing well conditions or changing operational set-points, thereby offering the potential to achieve rapidly a targeted pressure or flow rate of drilling fluid in the borehole with minor likelihood of over-shooting or over-compensating.

Referring now to FIG. 1, an embodiment of a drilling system 10 in accordance with the principles described herein is shown. Drilling system 10 includes a drill string 15 suspended from a drilling rig (not shown) through a blowout preventer stack (BOP) 40. Drill string 15 includes a plurality of drill pipe joints 18 coupled together end-to-end, a bottom-hole-assembly (BHA) 20 coupled to the lowest joint 18, and a drill bit 24 coupled to the lower end of BHA 20. During drilling operations, with force or weight is applied to the drill bit 24, also referred to as weight-on-bit (WOB), the rotating drill bit 24 engages the earthen formation and proceeds to form borehole 34 along a predetermined path toward a target zone. In general, drill bit 24 may be rotated with drill string 15 from the surface with a top drive or rotary table, and/or with a downhole mud motor. Casing 38 is installed and cemented in an upper portion of borehole 34 extending from the earth's surface 32. BOP 40 is secured to the upper end of casing 38.

An annular space or annulus 36 is formed between the sidewall of borehole 34 and drill string 15, and between casing 38 and drill string 15. In other words, annulus 36 extends through borehole 34 and casing 38. BOP 40 includes an annular flow path 41 in fluid communication with annulus 36.

Referring still to FIG. 1, a drilling fluid supply system 50 is provided to circulate a suitable drilling fluid 52, also referred to as mud or drilling mud, in order to cool drill bit 24, remove cuttings from the bottom of borehole 34, and maintain a desired pressure or pressure profile in borehole 34 during drilling operations. In this embodiment, fluid supply system 50 includes a drilling fluid reservoir or tank 54, a supply pump 56, a supply line 58 connected to the outlet of pump 56, and a rotatable supply coupling 60 coupling the supply line 58 to a drilling fluid inlet of drill string 15. Rotatable supply coupling 60 may a wash pipe assembly, for example. In addition, a drilling fluid discharge coupling 72 is mounted to the upper end of BOP 40. Drill string 15 extends through discharge coupling 72 and an annulus 74 is formed between the outer surface of drill string 15 and the inner surface of discharge coupling 72. Annular space 74 is in fluid communication with BOP flow path 41 and annular space 36.

During drilling operations, drilling fluid 52 from tank 54 is pressurized by pump 56 and sent through fluid supply line 58 and rotatable supply coupling 60 into drill string 15. The drilling fluid 52 flows down drill string 15 and is discharged at the borehole bottom through nozzles in drill bit 24. The drilling fluid 52 cools bit 24 and carries the formation cuttings to the surface through annulus 36, BOP flow path 41, and discharge coupling 72.

Referring still to FIG. 1, a drilling fluid flow rate and pressure control system 100 is coupled to discharge coupling 72 and is configured to regulate the flow rate and pressure of the drilling fluid in the borehole 34. Control system 100 includes a drilling fluid flow rate and pressure regulating device 110, a feedback controller system 200 for operating device 110, and a pressure sensor 102 for monitoring and communicating the pressure of the drilling fluid 52 disposed within and selectively flowing through discharge coupling 72. In this embodiment, regulating device 110 is a choke valve, and thus, may also be referred to herein as valve 110 or choke valve 110. Although sensor 102 is a pressure sensor in this embodiment, in other embodiments, the sensor (e.g., sensor 102) may be replaced or augmented with a flow rate sensor so that the flow rate of the returning drilling fluid may be more directly monitored and controlled.

An inlet conduit 104 provides fluid communication between discharge coupling 72 and choke valve 110, and a discharge conduit 105 provides fluid communication between choke valve 110 and mud tank 54 via a solids control system (not shown). The solids control system substantially separates the cuttings from the drilling fluid 52 at the surface, and may include hardware such as shale shakers, centrifuges, and automated chemical additive systems.

Referring now to FIG. 2, feedback controller system 200 monitors, operates, and regulates the performance of choke valve 110. In particular, choke valve 110 includes an actuator 150, a first valve position-indicating device 160, and a second valve position-indicating device 165. In this embodiment, first valve position-indicating device 160 is a rotary resolver, and thus, may also be referred to herein as rotary resolver 160. In addition, in this embodiment, second valve position-indicating device 165 is a linear position indicator located alongside actuator 150, and more specifically, a linear variable displacement transducer (LVDT). Thus, second valve position-indicating device 165 may also be referred to herein as linear position indicator or LVDT 165. In other embodiments, only one of a rotary resolver (e.g., rotary resolver 160) and a linear position indicator (e.g., LVDT 165) is provided.

Feedback controller system 200 also includes a process control engine 205 and a user interface 250 coupled to process control engine 205 with a communication link 270. In this embodiment, interface 250 includes one or more displays (e.g., monitors or single-line digital displays) with a data input capability or a data input device, and process control engine 205 includes a servo motor drive. Interface 250 is configured to display operational parameters and data, and to receive user input values for one or more of the operational parameters. Process control engine 205 is coupled to pressure sensor 102 with a cable 190 that transmits drilling fluid pressure measurements acquired by sensor 102 to control engine 205. In addition, process control engine 205 is coupled to actuator 150, rotary resolver 160, and linear position indicator 165 of choke valve 110 with cables 190 that transmit control signals and/or performance data between motor drive 205 and each of actuator 150, rotary resolver 160, and linear position indicator 165 to monitor and control the performance of choke valve 110.

In general, sensor 102 can be placed in a variety of locations within drilling system 10 and control system 100 to monitor and communicate the pressure (or, in some embodiments, flow rate) of the drilling fluid 52 disposed within discharge coupling 72. For example, in FIG. 1, sensor 102 is shown coupled to BOP 40, upstream from discharge coupling 72. In an alternate configuration, FIG. 2 shows sensor 102 coupled to inlet conduit 104, downstream from discharge coupling 72. Using methods known in the art, the data received from sensor 102 can be correlated to the drilling fluid pressure at a variety of locations, such as the pressure in discharge coupling 72, in BOP 40, in annulus 36, or within inlet conduit 104, for example.

Feedback controller system 200 is preferably electrically coupled to a larger drilling control system (not shown) configured to communicate with and to exchange data or control signals with system 200, as well as various other sensors, such as a downhole pressure sensor 22 on BHA 20, a weight-on-bit sensor, temperature sensors, a rotational speed senor, a motor torque sensor for a rotary table, or any of a number of sensors known in the art. The drilling control system is further configured to communicate with and to send commands to the actuators that influence the operation of drilling system 10, such as fluid pump 56, the downhole motor, top drive, or rotatory table that controls the rotational speed of drill string 15, etc.

Referring now to FIG. 2 and FIG. 3, choke valve 110 controls the flow rate and pressure of drilling fluid in conduit 104 and annulus 36. In this embodiment, choke valve 110 includes a valve body 115 having a drilling fluid inlet 116 coupled to conduit 104, a drilling fluid outlet 117 coupled to conduit 105, valve actuator 150, a yoke housing 170 coupled to actuator 150, a removable bonnet cap 146 coupling the actuator 150 and housing 170 to body 115, and a gantry assembly 180 for supporting valve actuator 150 and yoke housing 170 upon decoupling of bonnet cap 146 and body 115 (e.g., as may be done during repair or maintenance of valve 110). Inlet 116 and outlet 117 are each defined by a conduit having a connection flange at its end distal body 115. The connection flange for inlet 116 or outlet 117 may be studded or through bolted, for example. As best shown in FIG. 4, choke valve 110 also includes a flow and pressure control assembly 130 disposed in body 115 and a bonnet 145 extending from body 115 through cap 146 into housing 170.

Referring now to FIGS. 3 and 4, valve body 115 has a central axis 118, an outer surface 120, an externally threaded end 124, and a cylindrical inner chamber or cavity 125. Outer surface 120 includes three circumferentially spaced cylindrical recesses 121 disposed 90° apart. Each recess 121 includes a concentric, threaded hole for connection to gantry assembly 180. Thus, gantry assembly 180 can be selectively attached to body 115 at any one of recesses 121. A through-bore 126 extends from end 124 to cavity 125, an inlet passage extends from inlet 116 to cavity 125, and an outlet passage 117a extends from outlet 117 to cavity 125. Outlet passage 117a, end 124, cavity 125, and through-bore 126 are each coaxially aligned with axis 118. The inlet passage is oriented generally perpendicular to axis 118.

As best shown in FIG. 4, outlet passage 117a includes an annular recess 119 extending axially from cavity 125. Recess 119 includes an annular shoulder 129 dividing recess 119 into a first portion 119a extending axially from cavity 125 and a second portion 119b extending from shoulder 129 toward outlet 117. The diameter of first portion 119a is greater than the diameter of second portion 119b. A wear sleeve or liner 128 is seated within second portion 119b of recess 119.

Referring now to FIG. 4 and FIG. 5, flow and pressure control assembly 130 has a central axis 141 coaxially aligned with axis 118, and includes a tubular cage 132 positioned between inlet 116 and outlet 117, a cylindrical plug 133 slidably disposed within cage 132, a guide sleeve 138 coupled to cage 132, a biasing member 144 configured to urge sleeve 138 and cage 132 axially apart, and an elongate, cylindrical valve stem 140. In this embodiment, biasing member 144 is a wave spring. Cage 132, valve plug 133, sleeve 138, and stem 140 are each coaxially aligned with axis 141.

Cage 132 has a first end 132A, a second end 132B opposite of end 132A and slidingly seated in guide sleeve 138, and a plurality of circumferentially-spaced holes or apertures 132C disposed between ends 132A, 132B. During drilling operations, drilling fluid flows into cage 132 through apertures 132C and flows out of cage 132 through end 132A. Accordingly, apertures 132C may also be referred to as inlets and end 132A may also be referred to as outlet end. Valve plug 133 can be moved axially through cage 132 to control the flow of drilling fluid through apertures 132C. For example, plug 133 can be positioned to block the apertures 132C (i.e., a fully-closed position), to open fully the apertures 132C, or to block partially apertures 132C. When valve 110 is fully-closed, first end 134A of plug 133 contacts interior shoulder 132E of cage 132, as shown in FIG. 5. In some embodiments, even when plug 133 is positioned to block apertures 132C, some flow of fluid or pressure drop may occur in the fluid flow path between conduits 104 and 105 that includes pressure regulating device 110. In addition, cage 132 includes an outer annular recess 132D at end 132A and an inner annular shoulder 132E disposed between apertures 132C and end 132A. In this embodiment, cage 132 includes four uniformly circumferentially-spaced inlet apertures 132C, however, in other embodiments, the cage (e.g., cage 132) may have a different number of inlet apertures (e.g., inlet apertures 132C). An annular seal 148A is seated in outer recess 132D and sealingly engages cage 132 and body 115.

Referring still to FIG. 4 and FIG. 5, plug 133 includes a generally annular tip 134 and a generally cylindrical plug body 135 coupled to tip 134. Plug body 135 includes a first or open end 135A, a second or closed end 135B opposite end 135A, a cylindrical inner chamber 135C, and at least one through-bore 137 extending axially through body 135 from end 135B to chamber 135C. As will be explained, through-bore 137 reduces the amount of force needed to move the plug body 135 during operation. Plug tip 134 has a first end 134A distal body 135 and a second end 134B threadingly received by end 135A of body 135. An annular seal 148B is dispose between tip 134 and body 135 for sealing therebetween. In this embodiment, cage 132 and plug tip 134 are each made of a carbide material for enhanced abrasion resistance.

Guide sleeve 138 includes a first or open end 138A, a second or closed end 138B opposite end 138A, a cylindrical inner chamber 138C extending axially from end 138A, and a through-bore 138D extending co-axially through closed end 138B to chamber 138C. A set of annular seals 148D are disposed about bore 138D at end 138B and sealingly engage stem 141 extending therethrough. Inner chamber 138C includes a first annular shoulder 138E axially positioned proximal end 138A, and a second annular shoulder 138F axially positioned between shoulder 138E and end 138B. An annular seal 148C is disposed within guide sleeve 138 between shoulders 138E, 138F.

Valve stem 140 extends through bore 138D, sealingly engages seals 148D, and has an end connected to end 135B of plug 133, which is disposed in chamber 138C and slidingly engages guide sleeve 138. Annular seal 148C forms a dynamic seal with plug 133 as it moves relative to guide sleeve 138. Second end 132B of cage 132 is seated in end 138A, and wave spring 144 is axially positioned between shoulder 138E and end 132B of cage 132. Through-bore 137 allows fluid communication between cylindrical inner chambers 135C, 138C and thereby serves to balance pressure between chambers 135C, 138C, which reduces the amount of force needed to move plug body 135 during operation.

As best shown in FIG. 4, bonnet 145 has a first end 145A, a second end 145B opposite first end 145A, an outer surface 145C extending between ends 145A, 145B, and a through-bore 145D extending between ends 145A, 145B. Bonnet cap 146 includes an internally threaded first or open end 146A, a second or closed end 146B opposite end 146A, a through-bore 146C extending through closed end 146B, and a plurality of circumferentially-spaced tool engaging slots 147 on its outer surface (FIG. 3).

Referring to FIG. 4 and FIG. 5, the flow and pressure control assembly 130 is disposed within body 115 and extends through bore 126, cavity 125, and first portion 119a of recess 119. More specifically, guide sleeve 138 extends from through-bore 126 into cavity 125, and cage 132 extends from guide sleeve 138 into first portion 119A with apertures 132C positioned within cavity 125. Seals 148A are disposed between end 132A of cage 132 and body 115. Bonnet 145 extends into through-bore 126 and engages seals 148E adjacent guide sleeve closed end 138B, and valve stem 140 extends through bore 145D of bonnet 145. Bonnet cap 146 is threaded onto end 124 of body 115 and axially abuts an annular shoulder provided on outer surface 145C of bonnet 145, thereby axially compressing guide sleeve 138 and cage 132 between bonnet 145 and shoulder 129. Although, in this embodiment, guide sleeve 138 and bonnet 145 are separate components, in some other embodiments, the guide sleeve and bonnet features are formed as a single component.

Referring still to FIG. 4, valve actuator 150 includes a generally tubular housing 151 having a first end 151A and a second end 151B opposite first end 151A. In addition, valve actuator 150 includes a linear bearing sleeve 158 at first end 151A, a rotary motor 154 coupled to second end 151B, an externally threaded driveshaft 155 rotatably disposed within housing 151 and coupled to motor 154, and an internally threaded driveshaft sleeve 156 threadingly coupled to driveshaft 155 and slidingly engaging bearing sleeve 158. Ball bearings may be disposed between shaft 155 and sleeve 156 to more smoothly transfer rotation and linear motion therebetween. Driveshaft sleeve 156 and bearing sleeve 158 preferably include complementary features, such as a key and a mating keyway or mating splines that prevent driveshaft sleeve 156 from rotating relative to bearing sleeve 158 while allowing relative axial movement therebetween. The selective rotation of driveshaft 155 by motor 154 causes sleeve 156 to move axially in either direction relative to housing 151 depending on the direction of rotation of driveshaft 155. Driveshaft sleeve 156 is coupled to valve stem 140 and is thereby coupled to plug 133. Thus, axial movement of driveshaft sleeve 156 relative to housing 151 and body 115 results in axial movement of valve stem 140 and plug 133 relative to valve body 115, cage 132, and guide sleeve 138.

Rotary resolver 160 is axially disposed between housing 151 and motor 154 with driveshaft 155 passing therethrough. Accordingly, rotary resolver 160 may be considered to be a component of valve actuator 150. Resolver 160 is configured to detect the rotation of driveshaft 155 (direction of rotation, rotational speed, and rotational acceleration) and communicate that information to feedback controller system 200. In general, rotary resolver 160 may be any suitable rotary resolver known in the art.

Referring to FIGS. 3 and 4, yoke housing 170 is axially positioned between valve actuator 150 and bonnet cap 146 and has a first end 170A disposed about bonnet 145, a second end 170B opposite first end 170A and coupled to housing 151, an upper or top side 170C extending between ends 170A, 170B, a guide shaft 176 extending between ends 170A, 170B, and a stem coupler 173 extending between valve stem 140 and guide shaft 176. Shaft 176 is oriented parallel to valve stem 140 and driveshaft 155. Stem coupler 173 is fixably coupled to valve stem 140 and sleeve 156, and slidably coupled to shaft 176. Thus, axial movement of valve stem 140 is translated to stem coupler 173, which is guided by and move along shaft 176. A movable visual position indicator 172 is attached to coupler 173 and extends into a rectangular slot 171 provided in upper side 170C, thereby providing a visual indicator of the position of stem coupler 173, valve stem 140, and plug 133 coupled thereto. First end 170A of housing 170 includes a bonnet aperture 170D, and second end 170B of housing 170 includes an aperture 170E coaxially aligned with bonnet aperture 170D and an aperture 170F off-set from aperture 170E. Driveshaft sleeve 156 and bearing sleeve 158 extend through aperture 170E. An internally threaded nut 170G is fixed to end 170B about aperture 170F.

Actuator 150 is configured to move plug 133 axially relative to cage 132 and sleeve 138 by rotating shaft 155 to move sleeve 156, stem coupler 173, and valve stem 140 axially. The axial movement of plug 133 relative to cage 132 controls the flow through inlet apertures 132C of cage 132. In FIG. 4 and FIG. 5, inlet apertures 132C are completely closed by plug 133, but may be opened to various degrees by moving plug 133 relative to cage 132. The inclusion of inlet apertures 132C offers the potential for improved flow control and a more linear relationship between the axial movement of plug 133 and the resulting change in flow rate or pressure of a fluid passing from inlet 116 to outlet 117.

Referring now to FIG. 4, LVDT 165 is coupled to yoke housing 170 and includes a generally tubular body 166, a sensing element 168 disposed within tubular body 166, a linearly movable plunger rod 167 slidably disposed within sensing element 168, and a communications connector 169. Body 166 has a first or open end 166A threaded into nut 170G and a second or closed second end 166B disposed opposite end 166A. Communications connector 169 is coupled to second end 166B. A plunger extension rod 179 attached to stem coupler 173 extends parallel to shaft 176 through aperture 170F to plunger rod 167. A spring located within second end 166B biases rod 167 toward first end 166A. Axial movement of stem coupler 173 is transferred to rod 167, which is monitored by sensing element 168. In particular, when actuator 150 moves stem 140 and coupler 173, rod 179 transfers the force to plunger rod 167, which translates within sensing element 168. As a result, the electrical resistance of element 186 changes, thereby providing a basis for a signal that may be sensed by feedback controller system 200 to indicate the position of stem 140 and plug 133. In this embodiment, the correlation between the linear movement of plunger 167 and the change in resistance of element 168 is a mathematically linear relationship.

The output signal of LVDT 165 may relate to linear movement of valve plug 133 in a more direct manner than the output of a rotary resolver such as rotary resolver 160. For example, rotary resolver 160 detects angular movement of driveshaft 155; however, it is driveshaft 155 that causes sleeve 156 to move in a linear path by means of their engaging threads. Thus ascertaining linear motion with resolver 160 involves sensing and calculating, e.g. numerically integrating, the rotation of driveshaft 155 as well as correlating the rotational and linear interaction of driveshaft 155 and sleeve 156. Whereas, for linear position indicator 165, the linear movement of plunger 167 and thus the linear movement of stem 140 may be directly measured as a change in resistance of element 168 without numerical integration. Thus, rotary resolver 160 and LVDT 165, which are both coupled to valve plug 133, both function as sensors that measure and communicate the actual axial position of the valve plug 133 relative to the cage 132.

Referring now to FIG. 3 and FIG. 4, gantry assembly 180 includes a mounting post 181 received by one recess 121 in body 115, a cantilever support shaft 182 extending from post 181, an annular trolley 183 slidably mounted to shaft 182, a suspension rod 184 coupled to and extending outward from trolley 183, and a split-ring 185 attached to rod 184 opposite trolley 183. Mounting post 181 is configured to rotate about a central axis 181A oriented perpendicular to the outer surface of body 115 and axis 118. Split-ring 185 is clamped around bonnet 145 and axially positioned between bonnet cap 146 and yoke housing 170.

With bonnet cap 146 threadingly attached to valve body 115, shaft 182 extends parallel to axis 118. With bonnet cap 146 unthreaded from valve body 115, trolley 183 may slide along shaft 182 while supporting the weight of bonnet 145, as well as any other components coupled thereto. With bonnet 146 unthreaded from body 115, bonnet 145 can be slide axially away from body 115, leaving flow and pressure control assembly 130 within body 115. Shaft 182 may then be pivoted about axis 181A to provide access to the inside of body 115.

Referring now to FIG. 6, feedback controller system 200 of drilling fluid flow rate and pressure control system 100 is schematically shown. As previously described and shown in FIG. 2, controller system 200 includes process control engine 205 and user interface 250. In this embodiment, process control engine 205 includes a processor 210 coupled to non-transitory computer-readable storage device 220. In general, processor 210 can be implemented as a single processor or as multiple processors, and storage device 220 can be implemented as a single storage device or as multiple storage devices, each storage device coupled to processor 210 as a whole or each storage device coupled to one or more of the multiple processors in various embodiments. In addition, storage device 220 may include volatile storage (e.g., random access memory), non-volatile storage (e.g., hard disk drive, Flash storage, optical disc, etc.), or combinations of volatile and non-volatile storage.

In this embodiment, storage device 220 includes a process response module 222, a gain adjustment module 230, and a position control module 240, each of which comprises software executable by processor 210. Modules 222, 230, 240 are configured to cause the processor 210 to regulate the flow of fluid through control valve 110 based on data received from drilling fluid pressure sensor 102 to achieve a desired pressure or pressure profile in borehole 34. As previously described, in other embodiments, pressure sensor 102 is replaced by a flow rate sensor, thereby enabling controller system 200 to regulate the flow of fluid through control valve 110 based on data received from the flow rate sensor to achieve a desired flow rate of drilling fluid exiting borehole 34.

Continuing to reference FIG. 6, user interface 250 includes one or more display devices that convey information to an operator and receive data input by the operator. In general, user interface 250 can be implemented using one or more display technology known in that art, such as liquid crystal, cathode ray, plasma, light emitting diode, vacuum fluorescent, electroluminescent, a printer that provides a copy of results on a media such as paper, or any other display technology suitable for providing information to a user. In addition, user interface 250 may be sensitive to touch, i.e. a “touch screen,” or may be augmented by another means of entering responses or data, such as a keyboard or a pointing device. User interface 250 may be incorporated into a computing device such as a personal computer, a portable computer pad, or a smart telephone, for example.

In this embodiment, user interface 250 includes an operational command module 256 and operational status module 258. Operational command module 256 is configured to receive instructions or parameter values from a user and provide instructions to process control engine 205. For the instructions or parameter values, operational command module 256 may include default values, which are usable individually or in multiplicity when one or more pieces of information is not entered by a user. The instructions processed by command module 256 may include, for example, mode selection to choose manual or automatic operation and jog, i.e. movement, commands.

FIG. 7 presents a logic diagram corresponding to FIG. 6 so that the features of processor 210 and storage device 220 (FIG. 6) are blended together within the block for process control engine 205, As shown in FIG. 7, command module 256 includes a pressure set-point module 252 for receiving and providing a target upper limit for the pressure sensor 102. The operational status module 258 is configured to display information received from process control engine 205 and potentially other sources of data in systems 100, 200. In general, the information displayed by status module 258 may include, for example, a choke valve status indicator, the position of choke valve stem 140 or plug 133 relative to cage 132, and an indication of the power being used by valve actuator 150. In this embodiment, status module 258 includes display module 254 for displaying, for example, a recent value of pressure from sensor 102. An exemplary front view of user interface 250 is shown in FIG. 8.

As best shown in FIG. 7, process response module 222 is coupled to pressure sensor 102 with a process signal path 274 and also communicates with pressure set-point module 252. Path 274 is implemented, at least in part, by cable 190 previously described with respect to FIG. 2. In addition, process response module 222 is coupled to gain adjustment module 230 by a process adjustment signal path 280 and to position control module 240 by a displacement command path 282. Gain adjustment module 230 is also coupled to position control module 240 by a gain command path 284. Position control module 240 is further coupled to rotary resolver 160 of choke valve 110 with an actuator position signal path 276 and coupled to actuator 150 with a current amplifier 245 and an actuator control path 278. In FIG. 7, rotary resolver 160 is shown as the sole valve position-indicating device, however, in other embodiments, rotary resolver 160 is aided, superseded, or replaced by linear position indicator 165, with path 276 and the logic programming of position control module 240 modified accordingly.

Referring still to FIG. 7, process response module 222 includes a pressure error module 224 having a function 1 and coupled to sensor 102 and pressure set-point module 252, a controller module 226 coupled to the output of pressure error module 224, and a valve displacement command module 228 having a function 2 and coupled to the output of controller module 226 via path 280. In this embodiment, controller module 226 includes a partial-integral-differential (PID) controller and thus will also be called PID module 226. The output of displacement command module 228 is communicated to position control module 240 via displacement command path 282.

Gain adjustment module 230, which may also be referred to as gain module 230, includes a comparison module 234 having a first input node “w,” a second input node “z,” a first result node “no,” and a second result node “yes.” Gain module 230 further includes an adjustment threshold module 232 coupled to the “w” input node, a lower gain value module 236 coupled to the “no” result node, and a higher gain value module 237 coupled the “yes” result node of the comparison module 234. Second input node “z” is coupled to PID module 226 with process adjustment signal path 280. In this embodiment, only one comparison module 234 coupled to two gain modules 236, 237 are provided. However, in other embodiments, more than one comparison module (e.g., module 234) and more than two gain modules (e.g., gain modules 236, 237) may be included to enable selection of a variety of different gain values.

Position control module 240 includes a servo motor drive that monitors rotary resolver 160 and adjusts the position of valve stem 140 and plug 133 relative to cage 132 in choke valve 110 based on information received from rotary resolver 160, process response module 222, and gain adjustment module 230.

Referring to FIG. 6 and FIG. 7, the operation of drilling fluid flow rate and pressure control system 100 with feedback controller system 200 will now be described. A value designating a targeted or desired pressure, i.e. a pressure set-point, for drilling fluid 52 in borehole 34 is input or acquired by pressure set-point module 252. The pressure set-point value is then communicated from module 252 to pressure error module 224. In addition, the pressured measured by sensor 102 is communicated to pressure error module 224 and display module 254 via path 274. Using Function 1, module 224 calculates a pressure error, P_error, equivalent to the difference between the pressure set-point, P_set-point, and the measured pressure, P_measured. Function 1 is shown here as Equation 1:

P_error=P_set-point−P_measured   Equation 1

The result of Equation 1 may be positive, negative, zero valued. The P_error value is communicated to PID module 226, which produces an adjusted pressure error, P_error,adj, to achieve better stability for control system 100 using techniques known in the art. In some instances, adjusted pressure error, P_error,adj, will be equal to or nearly equal to pressure error, P_error. The adjusted pressure error is communicated from PID module 226 to displacement command module 228 and to comparison module 234 through path 280.

Using a Function 2, displacement command module 228 calculates a valve stem displacement command, ΔX, which is a value indicating or estimating the axial distance valve stem 140, and hence plug 133, should move from its the current position in an effort to achieve a desired change in drilling fluid pressure within inlet conduit 104, discharge coupling 72, and annulus 36. In other words, displacement command module 228 determines to what extent the valve 110 needs to be opened or closed to achieve the desired pressure. Function 2 for valve stem displacement command ΔX is shown here as Equation 2:

$\begin{array}{cc}\Delta X=P_{\mathrm{error},\mathrm{adj}}·\frac{{\mathrm{Length}}_{\mathrm{stroke},\max }}{P_{\mathrm{error},\max }}& \mathrm{Equation}2\end{array}$

• • Where: Length_stroke,max=The full distance of travel of valve plug 133 between a fully-open and a fully-closed condition relative to apertures 132C of cage 132.
    Module 228 communicates the valve stem displacement command, ΔX, to position control module 240 via path 282.

The process values, i.e. the pressure values, in Equations 1 and 2 may be associated with engineering units such as pounds-per-square-inch (PSI), kilopascal (KPa), or bar, for example, or may be associated with a digital value corresponding to a number between zero and the maximum value for the data bytes used by the processor or engine, such as processor 210 of process control engine 205. In at least one embodiment, process control engine 205 uses digital values in Equations 1 and 2 with each byte or piece of data comprising 16 bits or 16 digits; therefore, the maximum value handled by process control engine 205 in the embodiment is 32,767 when using a base-2 numbering system wherein the most-significant-bit is not utilized to indicate magnitude. In some such embodiments, the most-significant-bit may instead be assigned to represent the numeric sign (i.e., positive or negative) of the value, for example. This maximum value determines the maximum value of pressure error, P_error that can be calculated and recognized by process control engine 205. In the embodiment, the maximum result from Equation 1 is expressed as:

P_error,max=32,767   Equation 3

Process control engine 205 is configure so that in instances when the data that is input to the right-hand side of equation 1 would result in a value of P_error, having a magnitude (i.e. an absolute value) greater than P_error—max, magnitude of P_error is reduced to or is set equal to the value of P_error max for that instance. The same limitation in magnitude applies to the adjusted pressure error, P_error,adj that is to be generated for use in equation 2 of module 228. As previously stated for this example, pressure data, including error values, are handled as digital values by process control engine 205. The digital values may be correlated to a real-world value associated with an engineering unit by using a correlation known for sensor 102, for example by using a correlation provided by the manufacturer of sensor 102.

In other embodiments, the maximum error may be more or less than the value shown in Equation 3. For example, in other various embodiments, a higher maximum error value and greater resolution is possible due to the processor or process control engine (e.g. process control engine 205) being configured to operate with larger data bytes comprising 32-bits or 64-bits, for example. Less operation resolution and a lesser value of maximum error value would be anticipated in an embodiment in which the processor or process control engine (e.g. process control engine 205) were configured to operate with only 16-bit or 8-bit data bytes, for example.

Referring still to FIG. 7, comparison module 234 receives the adjusted pressure error P_error,adj, at node “z” and receives an adjustment threshold value, which is positive, from module 232 at node “w.” Module 234 compares the absolute value of the error at z to the threshold value at w. If the magnitude of the error at z is greater than or equal to the threshold, i.e. |z|≧w, then the difference between the pressure set-point and the measured pressure from sensor 102, as evaluated by Equation 1 and adjusted by PID module 226, is relatively high. In other words, the value of P_error and/or P_error,adj is considered to be relatively high. In that scenario, module 234 activates its “yes” node, commanding module 237 to send a higher gain value through path 284 to position control module 240, ultimately causing valve stem 140 and valve plug 133 to move at a relatively higher speed. On the other hand, if the magnitude of the error at z is less than the threshold value from module 232, i.e. |z|<w, then the value of P_error and/or P_error,adj is considered to be relatively low. In that scenario, module 234 activates its “no” node, commanding module 236 to send a lower gain value through path 284 to position control module 240, ultimately causing valve stem 140 and valve plug 133 to move at a relatively lower speed. Thus, gain module 230 changes the gain value communicated to position control module 240 to compensate for changes in various operation conditions, including changes in choke valve 105 and fluctuations in the pressure within borehole 34, i.e. within annular space 36.

During operation, position control module 240 may receive a positive, a negative, or a zero value displacement command ΔX from response module 222 and a gain value from adjustment module 230, and evaluates a positive, a negative, or a zero value output signal. That output signal is sent to and magnified by current amplifier 245 to send an actuator control signal through path 278 to actuator 150. As commanded by the actuator control signal, actuator 150 moves valve stem 140 and valve plug 133 in one of two directions to increase or decrease the flow rate through cage 132 of choke valve 110 or keeps valve stem 140 and valve plug 133 in their current position to maintain the flow rate. On a continuous or periodic basis, feed-back from resolver 160 via path 276 indicates the position of actuator 150, or more specifically, the position of valve stem 140 and plug 133. Module 240 uses feed-back from path 276 to adjust the actuator control signal of path 278 to achieve improved position accuracy and stability for actuator 150 and plug 133 coupled thereto.

During operation, the remaining distance of travel for plug 133 to reach a fully-open or a full-closed condition for valve 110 depends on the current location of valve plug 133 relative to apertures 132C in cage 132. In some instances, for example due to a sudden rise or sudden drop in pressure in annulus 36, the evaluated value of the valve stem displacement command ΔX may be greater than the remaining distance of travel for plug 133 to reach a fully-open or a full-closed condition. In such instances, process control engine 205 may reduce the valve stem displacement command ΔX or may reduce the actuator control signal sent through path 278 to actuator 150 in order to cause plug 133 to reach a fully-open or a full-closed condition without attempting to overshoot, i.e. to go beyond a fully-open or a full-closed condition. In other embodiments, valve 110 may be designed to accept an actuator control signal that commands actuator 150 and plug 133 to go beyond a fully-open or a full-closed condition while valve 100 limits the movement of plug to the fully-open or the full-closed condition.

Referring still to FIG. 7, controller system 200 may be described as including two interconnected and interrelated control loops for governing the pressure or flow rate of a drilling fluid in annulus 36. Within the first control loop, process response module 222 acts as the controller and is augmented by gain module 230. An aggregate actuator for the first control loop includes the combination of position control module 240, current amplifier 245, and choke valve 110 (including valve actuator 150 and valve position-indicating device 160). The process controlled by the first control loop is the flow of drilling fluid between inlet conduit 104 and discharge conduit 105, which corresponds to the pressure or flow rate within inlet conduit 104 or annulus 36. Sensor 102 provides feed-back about the process to module 222. During operation, the first control loop executes repeating cycles. The various cycles can have a similar duration in comparison to the other cycles or may vary in duration in some instances or embodiments. In a cycle, using the value prescribed by set-point module 252 and using data from pressure sensor 102 for feed-back, process response module 222 commands the aggregate actuator to adjust the fluid flow path between conduits 104 and 105, which includes altering the relative positions of plug 133 and cage 132. Cyclically, module 222 receives updated data from pressure sensor 102 and sends new commands to the aggregate actuator via path 282. The relative axial positions of plug 133 and cage 132 are not monitored by response module 222, the acting controller of the first control loop. The goal of the first control loop is to maintain the pressure within conduit 104 and annulus 36 equal to or nearly equal to the value prescribed by set-point module 252. When the set-point value in module 252 changes or the process signal from sensor 102 changes, the first control loop responds accordingly. Thus, the first control loop includes a sensor, a controller, and an actuator, which has been described as an aggregate actuator.

The second control loop assists the first loop in achieving the previously stated goal. The second control loop includes the components that were described as the aggregate actuator of the first control loop. Therefore, the second control loop includes the position control module 240, current amplifier 245, and choke valve 110 (including cage 132, plug 133, valve stem 140, actuator 150, and the valve position-indicating device, i.e. rotary resolver, 160). Position control module 240 may also be called a controller. The process controlled by the second control loop is the axial position of plug 133 relative to cage 132, which is adjustable by actuator 150. Rotary resolver 160 is a sensor to provide feed-back about the process to module 240. Thus, the second control loop includes a sensor, a controller, and an actuator.

During operation, the second control loop executes repeating cycles. The various cycles may have a similar duration in comparison to the other cycles or may vary in duration in some instances or embodiments. In a cycle, acting on a valve stem displacement command, ΔX, i.e. a set-point, module 240 commands actuator 150 to move valve stem 140 and plug 133 in one of two directions, while cage 132 remains at a fixed location within valve body 115. For example, in the embodiment of choke valve 110 of FIG. 4, motor 154 of actuator 150 rotates driveshaft 155 causing driveshaft sleeve 156 to move linearly by means of their engaging threads. The movement of driveshaft sleeve 156 extends or retracts plug 133. Simultaneously, rotary resolver 160 rotates and sends an actuator position signal to path 276. Module 240 tracks this signal, summing or otherwise evaluating the results to monitor the resulting position and, if preferred, the velocity of plug 133 or driveshaft sleeve 156. Module 240 further determines a net change in position of plug 133 occurring in the current operation cycle and compares that change in position against the command received via path 282. In response, when appropriate, module 240 adjusts the output signal transmitted through amplifier 245 and path 278. When control module 240 receives a new valve stem displacement command from path 282, the operation cycle repeats. Generally in this manner, the second control loop governs the state and the operation of choke valve 110 and acts as an aggregate actuator for the first control loop. Through the combined use of the first and second control loops, including equations 1 and 2 in controller system 200, changes in pressure sensed by sensor 102 are converted to changes in valve position, i.e., the axial position of plug 133 relative to cage 132.

Prior to or during the operation of the second control loop, the relative angular position or response of resolver 160 can be calibrated to the absolute position of plug 133 by methods known in the art. For example, an initial or “home” position of plug 133 may be established by moving valve stem 140 and plug 133 to a fully-extended position, causing plug end 134A to engage interior shoulder 132E of cage 132, which corresponds to the fully-closed condition. Module 240 registers this home position and uses subsequent readings from rotary resolver 160 to monitor, even to measure, the variable position of plug 133 while the second control loop operates. The fully-retracted position of valve stem 140 could alternatively be used as the initial position of plug 133. The output of LVDT 165 could also be used to calibrate the relative angular position or response of resolver 160.

In most conventional choke valves, the relationship between the valve stem position, i.e. the plug position, and the pressure measured by a sensor adjacent the valve inlet is non-linear. Thus, for example, changing the valve stem position by 1 cm does not cause a pressure change that is twice the magnitude of the pressure change resulting from a 0.5 cm change in valve stem position. However, in embodiments described herein, e.g. FIG. 4, the relationship between the valve stem position (i.e., the axial position of plug 133) and the resulting change in pressure in annulus 36 is more linear, at least in some instances. In particular, due to the frequent cycling of the two interconnected control loops, controller system 200 applies Equations 1 and 2 repeatedly and incrementally, i.e. in small steps. In this process, valve plug 133 and valve stem 140 may make repeated, small, and, perhaps, rapid positional changes while responding to changes in borehole pressure as monitored by sensor 102. The net result may be a more-direct relationship or a more balanced relationship between changes in pressure and valve displacement (i.e. plug movement), at least when plug movements are short and are governed by the two interconnected control loops. As a result, process control engine 205 offers the potential to achieve a desired flow more quickly with less over-shooting of the desired pressure. During the operation of the described embodiment, even though, equation 2 is mathematically linear, when applied repeatedly and incrementally, the two interconnected control loops cause the valve plug 133 to move in a non-linear fashion in response to the non-linear changes in pressure within conduit 104 adjacent borehole 34. However, in other embodiments, the result of applying equation 2 repeatedly may differ.

In the embodiments previously described in reference to FIG. 6 and FIG. 7, system 200 operates valve 110 to control the pressure of drilling fluid in annulus 36 based, at least in part, on the measured pressure from sensor 102 and the desired pressure from user interface 250. However, in other embodiments, the controller system (e.g., system 200) operates the drilling fluid choke valve (e.g., valve 110) to control the flow rate of drilling fluid through annulus 36 (e.g., volumetric flow rate or mass flow rate). Without being limited by this or any particular theory, the flow rate of drilling fluid through annulus 36 is inversely related to the pressure of drilling fluid in annulus 36. Thus, control of the flow rate of drilling fluid through annulus 36 provides an indirect means to control the pressure of drilling fluid in annulus 36. In such alternative embodiments, sensor 102 is replaced by flow rate sensor, and the controller system operates the choke valve in the same manner as previously described but with parameters relating to pressure being replaced by parameters relating to flow rate. Thus, for example, a desired flow rate is input into the command module (e.g., module 256), the display module (e.g., module 254) displays flow rate information from the flow rate sensor, the process response module (e.g., module 222) is coupled to the flow rate sensor, Functions 1 and 2 are based on flow rate values rather than pressure values, the gain is based on flow rate calculations, etc.

In the embodiments previously described, controller system 200 controls and operates choke valve 110. However, other drilling fluid choke valves may also be used in connection with controller system 200. For example, FIG. 9 illustrates an embodiment of a fluid flow rate and pressure regulating device or choke valve 310 that can be used in system 10 in the place of valve 110, and operated by system 200. Choke valve 310 includes a valve body 315, an actuator 350, a yoke 370 coupling actuator 350 to body 315, and a valve position-indicating device 360 integrated with actuator 350. In this embodiment, valve position-indicating device 360 is a rotary resolver. Actuator 350, including rotary resolver 360, is coupled to process control engine 205 by one or more cables 190.

Choke valve 310 also includes a bonnet 345 extending from body 315 into yoke 370 and a removable bonnet cap 346 threadably coupled to bonnet 345. Valve body 315 includes an inlet 316 and an outlet 317, each being defined by a conduit having a connection flange at an end distal body 315. As best shown in FIG. 10, a flow and pressure control assembly 330 is disposed in body 315 and held therein by bonnet 345.

Referring now to FIGS. 9 and 10, valve body 315 has a central axis 318, a generally cylindrical end 324 opposite outlet 317, and a cylindrical inner chamber or cavity 325. End 324 is externally threaded for threaded engagement with bonnet cap 346. An inlet passage 316A extends from inlet 316 to cavity 325, and an outlet passage 317A extends from outlet 317 to cavity 325. Outlet passage 317a, end 324, and cavity 325 are each coaxially aligned with axis 318, whereas inlet passage 316a is oriented generally perpendicular to axis 318.

Referring now to FIG. 10, flow and pressure control assembly 330 has a central axis 341 coaxially aligned with axis 318, and includes a tubular cage 332, a cylindrical plug 333 slidably disposed within cage 332, and an elongate valve stem 340 that couples to and controls the axial position of plug 333 within cage 332. Cage 332, plug 333, and stem 340 are each coaxially aligned with axis 341. Cage 332 includes a plurality of circumferentially-spaced inlet holes or apertures 332C extending radially therethrough. An annular flow path 349 is selectively and adjustably opened between cage 332 and plug 333 depending on the axial position of plug 333 within cage 332. Thus, flow path 349 controls the flow of fluids from inlet passage 316A to outlet passage 317A. The material of cage 332 positioned between apertures 332C provides added restriction to flow through valve 310, and offers the potential for improved flow control and a more-linear relationship between the axial movement of plug 333 and the resulting change in flow rate or pressure of drilling fluid in inlet passage 316A and annulus 36 as compared to conventional drilling fluid choke valves.

Referring again to FIG. 9, valve actuator 350 comprises a threaded screw and housing assembly 356, a right-angle gear box 355 coupled to assembly 356, a rotary motor 354 coupled to the gear box 355, and a hand wheel assembly 358 also coupled to gear box 355. Threaded screw and housing assembly 356 is coaxially aligned with body 315 and has one end coupled to yoke 370 and the other end coupled to gear box 355. Assembly 356 includes a threaded shaft or screw that is configured to rotate, thereby moving valve stem 340 and plug 333 axially relative to cage 332. Hand wheel assembly 358 functions as a manual means to rotate the threaded shaft within assembly 356. Rotary motor 354 functions as an automated means to rotate the threaded shaft within assembly 356. Thus, gear box 355 transfers torque from rotary motor 354 and hand wheel assembly 358 to assembly 356, and in particular, the screw rotatably disposed therein. Rotary resolver 360 is coupled to gear box 355 and motor 354 and communicates the axial position of plug 333 to controller system 200 in a similar manner as resolver 160 previously described.

While user interface 250 was described as a display exemplified by a monitor or a single-line digital display, in some embodiments the user interface 250 comprises an analog indicator and an adjustable control dial, such as an analog face on a pressure gauge and a potentiometer, for example.

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

Claims

1. A drilling system for forming a borehole in an earthen formation, the drilling system comprising:

a drill string extending through a blowout preventer;

a drilling fluid discharge coupling mounted to the blowout preventer;

a drilling fluid control system configured to control a pressure or flow rate of a drilling fluid flowing through the discharge coupling;

wherein the drilling fluid control system includes a flow rate and pressure regulating device, a feedback controller system configured to operate the regulating device, and a first sensor configured to measure an actual pressure or flow rate of the drilling fluid flowing through the discharge coupling;

wherein the regulating device includes a drilling fluid inlet in fluid communication with the discharge coupling, a drilling fluid outlet, an annular cage positioned between the inlet and the outlet, a valve plug slidingly disposed within the cage, an actuator, and a second sensor;

wherein the actuator is configured to adjust an axial position of the valve plug relative to the cage to selectively control the flow of drilling fluid through the cage from the inlet to the outlet, and the second sensor is configured to measure an actual axial position of the valve plug relative to the cage,

wherein the feedback controller system is configured to receive a desired pressure or flow rate and includes a process control engine configured to adjust the axial position of the valve plug relative to the cage based on a comparison of the actual pressure or flow rate measured by the first sensor and the desired pressure or flow rate and based on a comparison of the actual change in the axial position of the valve plug relative to the cage measured by the second sensor and a desired change in the axial position.

2. The drilling system of claim 1, wherein the process control engine is configured to:

determine a desired change in the axial position of the valve plug relative to the cage based on a comparison of the desired pressure or flow rate and the measured pressure or flow rate from the first sensor;

adjust the axial position of the valve plug relative to the cage with the actuator based on the desired change in the axial position of the valve plug;

determine an actual change in the axial position of the valve plug relative to the cage based on the measured axial positions from the second sensor; and

compare the desired change in the axial position of the valve plug relative to the cage to the actual change in the axial position valve plug relative to the cage while adjusting the axial position of the valve plug relative to the cage with the actuator.

3. The drilling system of claim 2, wherein the actuator includes a threaded shaft, a sleeve threaded onto the threaded shaft and coupled to the valve plug, and a motor configured to rotate the threaded shaft relative to the sleeve.

4. The drilling system of claim 3, wherein the second sensor is a rotary resolver.

5. The drilling system of claim 1, wherein the process control engine is configured to determine a gain based on the comparison of the desired pressure or flow rate and the measured pressure or flow rate, and adjust a speed of the change in the axial position of the valve plug relative to the cage based on the gain.

6. The drilling system of claim 2, wherein the feedback controller system further includes a user interface configured for inputting the desired pressure or flow rate and configured to display the actual pressure or flow rate of the drilling fluid disposed within the discharge coupling measured with the first sensor.

7. The drilling system of claim 2, wherein the cage includes a plurality of circumferentially spaced apertures in fluid communication with the drilling fluid inlet, wherein the valve plug is configured to control the flow of drilling fluid through the apertures.

8. A method for controlling the pressure or flow rate of drilling fluid flowing from a borehole through a valve, the method comprising:

(a) measuring the pressure or flow rate of the drilling fluid;

(b) obtaining a desired pressure or flow rate for the drilling fluid;

(c) comparing the measured pressure or flow rate with the desired pressure or flow rate;

(d) determining a desired change in an axial position of a valve plug within the valve based on the comparison in (c);

(e) adjusting the axial position of the valve plug based on the desired change in the axial position of the valve plug in (d);

(f) determining an actual change in the axial position of the valve plug during (e); and

(g) comparing the actual change in the axial position of the valve plug with the desired change in the axial position of the valve plug during (e).

9. The method of claim 8, further comprising:

(h) adjusting the axial position of the valve plug based on the comparison of the desire change in the axial position and the actual change in the axial position in (g).

10. The method of claim 8, wherein (a) comprises measuring the pressure or flow rate of the drilling fluid with a first sensor disposed upstream of the valve; and

wherein (f) comprises measuring the axial position of the valve plug with a position sensor coupled to the valve plug.

11. The method of claim 8, further comprising:

adjusting a speed of the change in the axial position in (e) based on the comparison the measured pressure or flow rate and the desired pressure or flow rate in (c).

12. The method of claim 11, wherein adjusting the speed of the change in the axial position comprises selecting a gain based on the comparison the measured pressure or flow rate and the desired pressure or flow rate in (c).

13. The method of claim 8, wherein (b) comprises inputting the desired pressure or flow rate at a user interface.

14. The method of claim 8, wherein (e) comprises:

sending an actuator control signal to an actuator of the valve; and

rotating a threaded shaft in the valve with the actuator.

15. The method of claim 8, wherein the desired change in the axial position of the valve plug is a function of the difference between the measured pressure or flow rate and the desired pressure or flow rate.

16. A method for controlling the pressure or flow rate of drilling fluid flowing from a borehole through a flow rate and pressure regulating device, the method comprising:

utilizing a first control loop to determine a desired change in a position of a valve plug within the regulating device to achieve a desired pressure or flow rate of the drilling fluid; and

utilizing a second control loop to adjust the actual position of the valve plug within the regulating device based on the desired change in the position of the valve plug from the first control loop.

17. The method of claim 16, further comprising:

communicating the desire pressure or flow rate of the drilling fluid from a user interface to the first control loop.

18. The method of claim 16, further comprising utilizing the first control loop to determine a gain that influences a speed for the desired change in position of the valve plug.

19. The method of claim C3, wherein the second control loop adjusts the speed of the change in the actual position of the valve plug based on the gain determined by the first control loop.

20. The method of claim 16 wherein first control loop comprises a first sensor configured to provide feed-back about the pressure or flow rate of drilling fluid, a first controller, and a first actuator;

wherein the second control loop comprises a second sensor, a second controller, and a second actuator.

wherein the first actuator comprises the second control loop.