Modular rotary steerable actuators, steering tools, and rotary steerable drilling systems with modular actuators

Modular actuators, steering tools, and rotary steerable drilling systems are presented herein. A modular actuator is disclosed for use in directing a drill string, which includes a housing proximate a drive shaft. The modular actuator includes a cartridge that is configured to couple to the outer periphery of the housing. A fluid reservoir is contained within the cartridge. A hydraulically actuated actuator piston, which is slidably disposed at least partially inside the cartridge, is movable between activated and deactivated positions. A hydraulic control system is also contained within the cartridge, fluidly coupling the fluid reservoir to the actuator piston. The hydraulic control system is configured to regulate movement of the actuator piston between the activated and deactivated positions such that the actuator piston selectively presses against and moves the drive shaft and thereby changes the direction of the drill string.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a U.S. national stage of International Patent Application No. PCT/US2012/042069, filed Jun. 12, 2012, the contents of which are incorporated herein by reference in its entirety.

TECHNICAL FIELD

The present disclosure relates generally to the drilling of boreholes, for example, during hydrocarbon exploration and excavation. More particularly, the present disclosure relates to steering apparatuses and steering actuators for directing drilling assemblies.

BACKGROUND

Boreholes, which are also commonly referred to as “wellbores” and “drill holes,” are created for a variety of purposes, including exploratory drilling for locating underground deposits of different natural resources, mining operations for extracting such deposits, and construction projects for installing underground utilities. A common misconception is that all boreholes are vertically aligned with the drilling rig; however, many applications require the drilling of boreholes with vertically deviated and horizontal geometries. A well-known technique employed for drilling horizontal, vertically deviated, and other complex boreholes is directional drilling. Directional drilling is generally typified as a process of boring a hole which is characterized in that at least a portion of the course of the bore hole in the earth is in a direction other than strictly vertical—i.e., the axes make an angle with a vertical plane (known as “vertical deviation”), and are directed in an azimuth plane.

Conventional directional boring techniques traditionally operate from a boring device that pushes or steers a series of connected drill pipes with a directable drill bit at the distal end thereof to achieve the borehole geometry. In the exploration and recovery of subsurface hydrocarbon deposits, such as petroleum and natural gas, the directional borehole is typically drilled with a rotatable drill bit that is attached to one end of a bottom hole assembly or “BHA.” A steerable BHA can include, for example, a positive displacement motor (PDM) or “mud motor,” drill collars, reamers, shocks, and underreaming tools to enlarge the wellbore. A stabilizer may be attached to the BHA to control the bending of the BHA to direct the bit in the desired direction (inclination and azimuth). The BHA, in turn, is attached to the bottom of a tubing assembly, often comprising jointed pipe or relatively flexible “spoolable” tubing, also known as “coiled tubing.” This directional drilling system—i.e., the operatively interconnected tubing, drill bit, and BHA—can be referred to as a “drill string.” When jointed pipe is utilized in the drill string, the drill bit can be rotated by rotating the jointed pipe from the surface, through the operation of the mud motor contained in the BHA, or both. In contrast, drill strings which employ coiled tubing generally rotate the drill bit via the mud motor in the BHA.

Directional drilling typically requires controlling and varying the direction of the wellbore as it is being drilled. Oftentimes the goal of directional drilling is to reach a position within a target subterranean destination or formation with the drill string. For instance, the drilling direction may be controlled to direct the wellbore towards a desired target destination, to control the wellbore horizontally to maintain it within a desired payzone, or to correct for unwanted or undesired deviations from a desired or predetermined path. Frequent adjustments to the direction of the wellbore are often necessary during a drilling operation, either to accommodate a planned change in direction or to compensate for unintended or unwanted deflection of the wellbore. Unwanted deflection may result from a variety of factors, including the characteristics of the formation being drilled, the makeup of the bottomhole drilling assembly, and the manner in which the wellbore is being drilled, as some non-limiting examples.

Various options are available for providing steering capabilities to a drilling tool for controlling and varying the direction of the wellbore. In directional drilling applications, for example, one option is to attach a bent-housing or a bent-sub downhole drilling motor to the end of the drilling string as a steering tool. When steering is required, the drill-pipe section of the drilling string can be restrained against rotation and the drilling motor can be pointed in a desired direction and operated for both drilling and steering in a “sliding drilling” mode. When steering is not required, the drilling string and the drilling motor can be rotated together in a “rotary drilling” mode. An advantage to this option is its relative simplicity. One disadvantage to this option, however, is that steering is typically limited to the sliding drilling mode. In addition, the straightness of the borehole in rotary drilling mode may be compromised by the presence of the bent drilling motor. Furthermore, since the drill pipe string is not rotated during sliding drilling, it is more susceptible to sticking in the wellbore, particularly as the angle of deflection of the wellbore from the vertical increases, resulting in reduced rates of penetration.

Directional drilling may also be accomplished with a “rotary steerable” drilling system wherein the entire drill pipe string is rotated from the surface, which in turn rotates the bottomhole assembly, including the drilling bit, connected to the end of the drill pipe string. In a rotary steerable drilling system, the drilling string may be rotated while the drilling tool is being steered either by being pointed or pushed in a desired direction (directly or indirectly) by a steering device. Some rotary steerable drilling systems include a component which is non-rotating relative to the drilling string in order to provide a reference point for the desired direction and a mounting location for the steering device(s). Alternatively, a rotary steerable drilling system may be “fully rotating”. Some advantages to rotary steerable drilling systems are that they can provide relatively high steering accuracy and they need not be operated in a sliding drilling mode to provide steering capabilities. In addition, the rate of penetration tends to be greater, while the wear of the drilling bit and casing are often reduced. However, rotary steerable drilling systems are relatively complex apparatuses and tend to be more expensive than their conventional counterparts.

As a third option, directional drilling may be accomplished using a combination of both rotary steerable drilling and sliding drilling. Rotary steerable drilling will typically be performed until such time that a variation or change in the direction of the wellbore is desired. At this point, rotation of the drill pipe string is stopped and sliding drilling, through use of the downhole motor, is commenced. Although the use of a combination of sliding and rotary drilling may permit satisfactory control over the direction of the wellbore, many of the problems and disadvantages associated with sliding drilling are still encountered.

Various attempts have been made to provide rotary steerable drilling systems which address these problems. Numerous examples of prior art rotary steerable drilling apparatuses are disclosed in U.S. Pat. No. 6,769,499, to Edward J. Cargill et al., and U.S. Pat. No. 7,413,034, to Kennedy Kirkhope, both of which are incorporated herein by reference in their respective entireties and for all purposes. In many of these disclosed configurations, however, servicing the individual actuators often requires opening the steering tool, which is typically a very complicated and time consuming process. Exposing the internal hydraulics of the steering system is also generally not desirable due to environmental corrosion and other deleterious effects. In addition, once replaced, each of the actuators must then be tested at the rig site to ensure proper functionality, which adds to downtime and repair costs. There remains a need for improved and simplified rotary steerable drilling configurations which reduce servicing costs and down time, simplify installment and testing, and minimize environmental exposure of the tool.

SUMMARY

Aspects of the present disclosure are directed to modular rotary steerable actuators which package all of the components necessary to provide the functionality of a steering actuator into a single cartridge that is mounted to the exterior of the steering tool. In some configurations, the modular actuator is a self-contained apparatus with a pump, a fluid reservoir, a pressure compensator piston, a solenoid control valve, and an actuator piston, all of which are packaged in a common housing. By limiting external connections to electrical control logic, the modular actuator can reduce leak points and permits oil filling and verification of “on the shelf” cartridges. The foregoing configuration also allows for ease of replacement of the individual actuators from outside the steering tool with only electrical control and positional feedback connections. The modular actuator also provides the benefits and capabilities of a hydraulic actuator without the “at rig” servicing complications often associated with prior art directional steering systems. Another advantage is the ability to stock complete replacement actuator cartridges that quickly and easily replace onboard cartridges to rapidly return the steering tool to downhole readiness. Isolating the hydraulic circuits also help to simplify differing system pressures. Another advantage is the ability to use more of the common cartridges to scale into larger tools.

Some embodiments of the present disclosure are directed to a steering tool for use in drilling a borehole. The steering tool may be used, for example, for drilling vertical and/or non-vertical boreholes. The steering tool is a hydro-mechanical tool with a plurality of self-contained, separately actuable, circumferentially spaced modular actuators. The steering tool is intended to be incorporated into a drill string. The steering tool may be incorporated into a drill string in several different configurations depending, for example, on the intended drilling application. In some configurations, the steering tool is configured as a component of a drilling motor. The steering tool can also be adapted as a component of a rotary steerable drilling system. In some configurations, the steering tool is adapted as a component of a fully rotating rotary steerable drilling system.

Aspects of the present disclosure are directed to a modular actuator for use in directing a drill string, which includes a housing and a drive shaft. The modular actuator includes a cartridge that is configured to couple to the outer periphery of the drill string housing. A fluid reservoir is contained within the cartridge. A hydraulically actuated actuator piston, which is slidably disposed at least partially inside the cartridge, is movable between first and second positions. A hydraulic control system is also contained within the cartridge, fluidly coupling the fluid reservoir to the actuator piston. The hydraulic control system is configured to regulate movement of the actuator piston between the first and second positions such that the actuator piston selectively moves the drive shaft and thereby changes the direction of the drill string.

According to other aspects of the present disclosure, a steering tool is presented for use in directing a drill string when drilling a borehole in an earth formation. The drill string includes a drive shaft and a swash plate. The steering tool includes a tubular housing with an exterior surface and a housing bore configured to receive therethrough the drive shaft. The steering tool also includes a plurality of modular actuators circumferentially spaced about the exterior surface of the housing. Each of the modular actuators includes: a cartridge coupled to the exterior surface of the housing; a fluid reservoir sealed within the cartridge; a hydraulically actuated actuator piston slidably disposed at least partially inside the cartridge, the actuator piston being movable between deactivated and activated positions; and, a hydraulic control system sealed within the cartridge and fluidly coupling the fluid reservoir to the actuator piston. The hydraulic control system is configured to regulate the movement of the actuator piston between the deactivated and activated positions such that the actuator piston selectively moves the drive shaft and thereby changes the direction of the drill string.

A rotary steerable drilling system is also featured in accordance with aspects of this disclosure. The rotary steerable drilling system includes a drill-pipe string and a tubular housing operatively coupled to a distal end of the drill-pipe string. The tubular housing has an exterior surface and a housing bore. A drive shaft, which extends through the tubular housing, includes a plurality of ramped surfaces. A drill bit is rotatably coupled to the tubular housing via the drive shaft. The rotary steerable drilling system also includes a steering controller and a plurality of modular actuators circumferentially spaced about the exterior surface of the housing. Each of the modular actuators includes: a cartridge coupled to the exterior surface of the housing; an electrical connector electrically connecting the modular actuator with the steering controller; a fluid reservoir sealed within the cartridge; a hydraulically actuated actuator piston slidably disposed at least partially inside the cartridge, the piston being movable between deactivated and activated positions; and, a hydraulic control system sealed within the cartridge and fluidly coupling the fluid reservoir to the actuator piston. The hydraulic control system is configured to regulate movement of the actuator piston from the deactivated position to the activated position such that the actuator piston selectively presses against one of the ramped surfaces of the drive shaft and thereby changes the direction of the drill string.

The above summary is not intended to represent each embodiment or every aspect of the present disclosure. Rather, the foregoing summary merely provides an exemplification of some of the novel aspects and features set forth herein. The above features and advantages, and other features and advantages of the present disclosure, will be readily apparent from the following detailed description of the exemplary embodiments and modes for carrying out the present invention when taken in connection with the accompanying drawings and appended claims.

DETAILED DESCRIPTION OF THE ILLUSTRATED EMBODIMENTS

While this invention is susceptible of embodiment in many different forms, there are shown in the drawings and will herein be described in detail embodiments of the invention with the understanding that the present disclosure is to be considered as an exemplification of the principles of the invention and is not intended to limit the broad aspects of the invention to the embodiments illustrated. To that extent, elements and limitations that are disclosed, for example, in the Abstract, Summary, and Detailed Description sections, but not explicitly set forth in the claims, should not be incorporated into the claims, singly or collectively, by implication, inference or otherwise. For purposes of the present detailed description, unless specifically disclaimed, the singular includes the plural and vice versa; the words “and” and “or” shall be both conjunctive and disjunctive; the word “all” means “any and all”; the word “any” means “any and all”; and the word “including” means “including without limitation.” Moreover, words of approximation, such as “about,” “almost,” “substantially,” “approximately,” and the like, can be used herein in the sense of “at, near, or nearly at,” or “within 3-5% of;” or “within acceptable manufacturing tolerances,” or any logical combination thereof, for example.

Referring now to the drawings, wherein like reference numerals refer to like components throughout the several views,FIG. 1illustrates an exemplary directional drilling system, designated generally as10, in accordance with aspects of the present disclosure. Many of the disclosed concepts are discussed with reference to drilling operations for the exploration and/or recovery of subsurface hydrocarbon deposits, such as petroleum and natural gas. However, the disclosed concepts are not so limited, and can be applied to other drilling operations. To that end, the aspects of the present disclosure are not necessarily limited to the arrangement and components presented inFIGS. 1 and 2. For example, many of the features and aspects presented herein can be applied in horizontal drilling applications and vertical drilling applications without departing from the intended scope and spirit of the present disclosure. In addition, it should be understood that the drawings are not necessarily to scale and are provided purely for descriptive purposes; thus, the individual and relative dimensions and orientations presented in the drawings are not to be considered limiting. Additional information relating to directional drilling systems can be found, for example, in U.S. Patent Application Publication No. 2010/0259415 A1, to Michael Strachan et al., which is entitled “Method and System for Predicting Performance of a Drilling System Having Multiple Cutting Structures” and is incorporated herein by reference in its entirety for all purposes.

The directional drilling system10exemplified inFIG. 1includes a tower or “derrick”11, as it is most commonly referred to in the art, that is buttressed by a derrick floor12. The derrick floor12supports a rotary table14that is driven at a desired rotational speed, for example, via a chain drive system through operation of a prime mover (not shown). The rotary table14, in turn, provides the necessary rotational force to a drill string20. The drill string20, which includes a drill pipe section24, extends downwardly from the rotary table14into a directional borehole26. As illustrated in the Figures, the borehole26may travel along a multi-dimensional path or “trajectory.” The three-dimensional direction of the bottom54of the borehole26ofFIG. 1is represented by a pointing vector52.

A drill bit50is attached to the distal, downhole end of the drill string20. When rotated, e.g., via the rotary table14, the drill bit50operates to break up and generally disintegrate the geological formation46. The drill string20is coupled to a “drawworks” hoisting apparatus30, for example, via a kelly joint21, swivel28, and line29through a pulley system (not shown). The drawworks30may comprise various components, including a drum, one or more motors, a reduction gear, a main brake, and an auxiliary brake. During a drilling operation, the drawworks30can be operated, in some embodiments, to control the weight on bit50and the rate of penetration of the drill string20into the borehole26. The operation of drawworks30is generally known and is thus not described in detail herein.

During drilling operations, a suitable drilling fluid (commonly referred to in the art as “mud”)31can be circulated, under pressure, out from a mud pit32and into the borehole26through the drill string20by a hydraulic “mud pump”34. The drilling fluid31may comprise, for example, water-based muds (WBM), which typically comprise a water-and-clay based composition, oil-based muds (OBM), where the base fluid is a petroleum product, such as diesel fuel, synthetic-based muds (SBM), where the base fluid is a synthetic oil, as well as gaseous drilling fluids. Drilling fluid31passes from the mud pump34into the drill string20via a fluid conduit (commonly referred to as a “mud line”)38and the kelly joint21. Drilling fluid31is discharged at the borehole bottom54through an opening or nozzle in the drill bit50, and circulates in an “uphole” direction towards the surface through an annular space27between the drill string20and the side56of the borehole26. As the drilling fluid31approaches the rotary table14, it is discharged via a return line35into the mud pit32. A variety of surface sensors48, which are appropriately deployed on the surface of the borehole26, operate alone or in conjunction with downhole sensors70,72deployed within the borehole26, to provide information about various drilling-related parameters, such as fluid flow rate, weight on bit, hook load, etc., which will be explained in further detail below.

A surface control unit40may receive signals from surface and downhole sensors and devices via a sensor or transducer43, which can be placed on the fluid line38. The surface control unit40can be operable to process such signals according to programmed instructions provided to surface control unit40. Surface control unit40may present to an operator desired drilling parameters and other information via one or more output devices42, such as a display, a computer monitor, speakers, lights, etc., which may be used by the operator to control the drilling operations. Surface control unit40may contain a computer, memory for storing data, a data recorder, and other known and hereinafter developed peripherals. Surface control unit40may also include models and may process data according to programmed instructions, and respond to user commands entered through a suitable input device44, which may be in the nature of a keyboard, touchscreen, microphone, mouse, joystick, etc.

In some embodiments of the present disclosure, the rotatable drill bit50is attached at a distal end of a steerable drilling bottom hole assembly (BHA)22. In the illustrated embodiment, the BHA22is coupled between the drill bit50and the drill pipe section24of the drill string20. The BHA22may comprise a Measurement While Drilling (MWD) System, designated generally at58inFIG. 1, with various sensors to provide information about the formation46and downhole drilling parameters. The MWD sensors in the BHA22may include, but are not limited to, a device for measuring the formation resistivity near the drill bit, a gamma ray device for measuring the formation gamma ray intensity, devices for determining the inclination and azimuth of the drill string, and pressure sensors for measuring drilling fluid pressure downhole. The MWD may also include additional/alternative sensing devices for measuring shock, vibration, torque, telemetry, etc. The above-noted devices may transmit data to a downhole transmitter33, which in turn transmits the data uphole to the surface control unit40. In some embodiments, the BHA22may also include a Logging While Drilling (LWD) System.

In some embodiments, a mud pulse telemetry technique may be used to communicate data from downhole sensors and devices during drilling operations. Exemplary methods and apparatuses for mud pulse telemetry are described in U.S. Pat. No. 7,106,210 B2, to Christopher A. Golla et al., which is incorporated herein by reference in its entirety. Other known methods of telemetry which may be used without departing from the intended scope of this disclosure include electromagnetic telemetry, acoustic telemetry, and wired drill pipe telemetry, among others.

A transducer43can be placed in the mud supply line38to detect the mud pulses responsive to the data transmitted by the downhole transmitter33. The transducer43in turn generates electrical signals, for example, in response to the mud pressure variations and transmits such signals to the surface control unit40. Alternatively, other telemetry techniques such as electromagnetic and/or acoustic techniques or any other suitable techniques known or hereinafter developed may be utilized. By way of example, hard wired drill pipe may be used to communicate between the surface and downhole devices. In another example, combinations of the techniques described may be used. As illustrated inFIG. 1, a surface transmitter receiver80communicates with downhole tools using, for example, any of the transmission techniques described, such as a mud pulse telemetry technique. This can enable two-way communication between the surface control unit40and the downhole tools described below.

According to aspects of this disclosure, the BHA22can provide some or all of the requisite force for the bit50to break through the formation46(known as “weight on bit”), and provide the necessary directional control for drilling the borehole26. In the embodiments illustrated inFIGS. 1 and 2, the BHA22may comprise a drilling motor90and first and second longitudinally spaced stabilizers60and62. At least one of the stabilizers60,62may be an adjustable stabilizer that is operable to assist in controlling the direction of the borehole26. Optional radially adjustable stabilizers may be used in the BHA22of the steerable directional drilling system10to adjust the angle of the BHA22with respect to the axis of the borehole26. A radially adjustable stabilizer provides a wider range of directional adjustability than is available with a conventional fixed diameter stabilizer. This adjustability may save substantial rig time by allowing the BHA22to be adjusted downhole instead of tripping out for changes. However, even a radially adjustable stabilizer provides only a limited range of directional adjustments. Additional information regarding adjustable stabilizers and their use in directional drilling systems can be found in U.S. Patent Application Publication No. 2011/0031023 A1, to Clive D. Menezes et al., which is entitled “Borehole Drilling Apparatus, Systems, and Methods” and is incorporated herein by reference in its entirety.

As shown in the embodiment ofFIG. 2, the distance between the drill bit50and the first stabilizer60, designated as L1, can be a factor in determining the bend characteristics of the BHA22. Similarly, the distance between the first stabilizer60and the second stabilizer62, designated as L2, can be another factor in determining the bend characteristics of the BHA22. The deflection at the drill bit50of the BHA22is a nonlinear function of the distance L1, such that relatively small changes in L1may significantly alter the bending characteristics of the BHA22. With radially movable stabilizer blades, a dropping or building angle, for example A or B, can be induced at bit50with the stabilizer at position P. By axially moving stabilizer60from P to P′, the deflection at bit50can be increased from A to A′ or B to B′. A stabilizer having both axial and radial adjustment may substantially extend the range of directional adjustment, thereby saving the time necessary to change out the BHA22to a different configuration. In some embodiments the stabilizer may be axially movable. The position and adjustment of the second stabilizer62adds additional flexibility in adjusting the BHA22to achieve the desired bend of the BHA22to achieve the desired borehole curvature and direction. As such, the second stabilizer62may have the same functionality as the first stabilizer60. While shown in two dimensions, proper adjustment of stabilizer blades may also provide three dimensional turning of BHA22.

FIG. 3illustrates a portion of a drill string system100of the type used for drilling a borehole in an earth formation. The drill string system100ofFIG. 3is represented by a bottom hole assembly (BHA)110and a rotary steering tool assembly, designated generally at112. The drill string system100ofFIG. 3can take on various forms, optional configurations, and functional alternatives, including those described above with respect to the directional drilling system10exemplified inFIGS. 1 and 2, and thus can include any of the corresponding options and features. Moreover, only selected components of the drill string system100have been shown and will be described in additional detail hereinbelow. Nevertheless, the drill string systems discussed herein, including the corresponding BHA and steering tool configurations, can include numerous additional, alternative, and other well-known peripheral components without departing from the intended scope and spirit of the present disclosure. Seeing as these components are well known in the art, they will not be described in further detail.

In the embodiment illustrated inFIG. 3, the steering tool112is configured as part of a drilling motor114having a motor housing116and a motor drive shaft118(FIG. 4; also referred to herein as “drive shaft”). In this instance, the steering tool112chassis is part of the drivetrain into which the actuator steering mechanism and electronics packages (e.g., steering controller160ofFIG. 7) would mount. It is also conceivable that the steering mechanism and electronics could be made entirely replaceable from outside the steering tool112with the tool chassis providing the requisite mechanical support. Alternatively, the steering tool112can be configured as a component of a rotary steerable drilling system of the type in which the steering tool112is rotatably connected with the drill string. In this configuration, the housing116would be part of the steering tool112, which could be outfitted with an optional borehole engaging device for inhibiting the steering tool112from rotating when the drill string is rotated. Optionally, the steering tool112can be configured as a component of a fully rotating rotary steerable drilling system, which may be of the type in which the steering tool112is fixedly connected within the drill string.

A rotatable drill bit (e.g., drill bit50ofFIG. 1) is located at a distal end of the drill string system100, projecting from the elongated, tubular housing116ofFIG. 3. The tubular housing116is operatively attached or otherwise coupled, e.g., via a top sub (not shown), to the distal end of a drill pipe or drill-pipe string (e.g., which could be a portion of the drill pipe section24ofFIG. 1). A bottom (or “bit”) sub120couples the drive shaft118of the mud motor assembly114to a drill bit. By using a Measurement While Drilling (MWD) Tool, such as MWD58ofFIG. 1, a directional driller can steer the bit to a desired target zone. As seen inFIG. 4, a swash plate122is mounted at an angle on drive shaft118, proximate to the housing116. The swash plate122is operable to draw mechanical power from the driveshaft118to help create hydraulic power for the modular actuators124A-D, as will be developed in further detail below.

The motor assembly114ofFIG. 3can be a positive displacement motor (PDM) assembly, which may be in the nature of SperryDrill® or SperryDrill® XL/XLS series positive displacement motor assemblies available from Halliburton of Houston, Tex. In this instance, the PDM motor assembly114includes a multi-lobed stator (not shown) with an internal passage within which is disposed a multi-lobed rotor (not shown). The PDM assembly114operates according to the Moineau principle—essentially, when pressurized fluid is forced into the PDM assembly and through the series of helically shaped channels formed between the stator and rotor, the pressurized fluid acts against the rotor causing nutation and rotation of the rotor within the stator. Rotation of the rotor generates a rotational drive force for the drill bit, as will be developed in further detail below.

The distal end of the rotor is coupled to the rotatable drill bit via the drive shaft118and bit sub120such that the eccentric power from the rotor is transmitted as concentric power to the bit. In this manner, the PDM motor assembly114can provide a drive mechanism for the drill bit which is at least partially and, in some instances, completely independent of any rotational motion of the drill string generated, for example, via rotation of a top drive in the derrick mast and/or the rotary table14on the derrick floor12ofFIG. 1. Directional drilling may also be performed by rotating the drill string100while contemporaneously powering the PDM assembly114, thereby increasing the available torque and drill bit speed. The drill bit may take on various forms, including diamond-impregnated bits and specialized polycrystalline-diamond-compact (PDC) bit designs, such as the FX and FS Series™ drill bits available from Halliburton of Houston, Tex., for example.

An external surface117of the housing116shown inFIG. 3defines a plurality elongated cavities119extending parallel to one another and longitudinally with respect to the drill string100. In the illustrated embodiment, there are four cavities119in the housing116, only two of which are visible in the drawings, but two more cavities are located on opposite sides of the housing116to the ones shown. Nested within each cavity119is a modular actuator124which is operable to direct the drill string100during a drilling operation, as will be developed in further detail below. As seen inFIG. 4, there are four modular actuators124A,124B,124C and124D circumferentially spaced equidistant from one another about the outer periphery of the housing116. In at least some embodiments, all of the modular actuators124A-D are structurally identical. An optional actuator shield126can be employed to cover and protect each of the modular actuators124A-D. Although shown with four modular actuators124A-D, the rotary steering tool assembly112can include greater or fewer than the number shown.

Each modular actuator124A-D includes a respective cartridge128A,128B,128C and128D that is configured to couple to the outer periphery of the housing116. As seen inFIGS. 5 and 6, for example, the cartridge128includes an elongated tubular body with a window130formed therethrough, and a pair of pistons132and134slidably disposed at least partially inside the cartridge128. The first piston132(also referred to herein as “pump piston”) projects out from an uphole longitudinal end of the elongated tubular body128, whereas the second piston134(also referred to herein as “actuator piston”) slides across and at least partially obstructs the window130, e.g., when moving from a deactivated position to an activated position. The window130is designed to fit onto and receive therein a complementary shaft ramp140protruding radially outward from the drive shaft118, which is best seen inFIG. 4. The shaft ramps140may be mounted onto the drive shaft118via a bearing142. Additional attachment means may be employed for mechanically coupling each cartridge128A-D to the housing116and/or drive shaft118. It is desirable, in at least some embodiments, that the cartridges128A-D be removably coupled to the housing116, e.g., for ease of installation and serviceability.

In the illustrated example, the first piston132faces “uphole” and translates generally rectilinearly along a common axis with the second piston134, which faces and translates generally rectilinearly “downhole.” The pistons132,134are movable from respective first “deactivated” positions (e.g.,132′ and134′ inFIG. 6) to respective second “activated” positions (e.g.,132″ and134″ inFIG. 6), and back. Each of the modular actuators124A-D contacts a portion of the swash plate122. For instance, the pump piston132A of the first actuator124A extends through a complementary housing window115in housing116and, as shown inFIG. 4, initially engages the top-most central portion of the swash plate122. Likewise, the pump piston132B of the second actuator124B extends through a corresponding housing window115in housing116and initially engages the right-most portion of the swash plate122, which is approximately 90-degrees clockwise from where the first actuator124A contacts the swash plate122. Moreover, the pump piston132C of the third actuator124C extends through a corresponding housing window115in housing116and, as shown inFIG. 4, initially engages the left-most portion of the swash plate122, which is approximately 90-degrees counterclockwise from the first actuator124A. Finally, the pump piston132D of the fourth actuator124D extends through a corresponding housing window115in housing116, and is shown inFIG. 4initially engaging the bottom-most central portion of the swash plate122, which is approximately 180-degrees clockwise from where the first actuator124A contacts the swash plate122. An optional bushing148, which is shown in one example as a cylindrical polymeric cap coupled to the distal end of the piston132proximate the swash plate122, operates to distribute loading caused by the angle of the swash plate.

FIGS. 3 and 4illustrate what may be considered a typical X-Y steering system. In accordance with some embodiments, a minimum of two modular actuators124per plane are required. By way of example, and not limitation, activation of the first modular actuator124A urges or otherwise moves the actuator piston134A downhole such that a ramped surface of the piston134A presses downwardly against a respective one of the shaft ramps140thereby redirecting the drive shaft118. The actuator piston of the opposing same-plane actuator, i.e., the fourth modular actuator124D in this example, will contemporaneously retract through corresponding return springs. In so doing, the first modular actuator124A operates to steer or otherwise direct the drive shaft118and, thus, the drill string system100vertically downward along the y-axis ofFIG. 4. To steer or otherwise direct the drill string system100vertically upward along the y-axis ofFIG. 4, the fourth modular actuator124D is activated while the actuator piston of the first modular actuator124A is allowed to retract. Steering or otherwise turning the drill string system100to starboard (e.g., towards the lower-left corner ofFIG. 4) includes activation of the second modular actuator124B while the actuator piston of the third modular actuator124C is allowed to retract. Contrastingly, turning the drill string system100to port (e.g., towards the upper-right corner ofFIG. 4) includes activation of the third modular actuator124C while the actuator piston of the second modular actuator124B is allowed to retract.

In applications where larger forces are required (e.g., for larger tools), the drill string system100can employ additional and/or larger modular actuators124. For instance, larger forces can be acquired by use of additional modular actuators124that are slightly out of plane with the primary modular actuators124(e.g., the four shown inFIG. 4) and acting on additional shaft ramps140. It is also contemplated to provide a rotary steering tool assembly112which employs fewer than four modular actuators124for directional steering capabilities. Direction of steering can be determined by pushing or moving the shaft into the desired direction of steer, as described above, or by bending the shaft between spherical supports in which case the actuators are operated to steer in the opposite direction to which you push.

A first return spring136biases the first piston132towards the deactivated position132′, whereas a second return spring138biases the second piston134towards the deactivated position134′. The rotary steering tool assembly112can be a “normally open” design. By way of non-limiting example, the second return spring138biases the actuator piston134towards the deactivated position134″. In this optional configuration, when one of the modular actuators124is deactivated or otherwise rendered inoperable, the corresponding actuator piston134is biased away from the shaft ramp140and toward the deactivated position134′ via the return spring138, and the ramped surface of the actuator piston134does not apply a steering force to the drive shaft118via the shaft ramp140. With all of the deactivated modular actuators128being biased out of steering engagement with the drive shaft118, the rotary steering tool assembly112is a normally open “fail safe” configuration, which helps to ensure that the steering system defaults into a straight ahead condition, for example, on failure of the steering electronics. The first return spring136is shown loaded into a side window144of the cartridge128installed outside of an internal oil environment146to maximize useable oil space inside the cartridge128.

In accordance with aspects of the disclosed concepts, the individual modular actuators124each contains all the mechanical and hydraulic components necessary to operate as a hydraulic rotary steerable actuator, e.g., in a single plane. Turning toFIG. 7, for example, each of the modular actuators124A-D includes a respective cartridge128A-D from which project respective opposing pistons132A-D and134A-D. The first (“pump”) pistons132A-D project from respective longitudinal “uphole” ends of the cartridges128A-D to selectively engage the swash plate122, whereas the second pistons134A-D are disposed at least partially inside the cartridges128A-D and slidable to selectively press against a drive shaft118(e.g., via complementary shaft ramps140) to displace the shaft118(e.g., directly or in bending) prompting a change of drilling direction. First return springs136A-D bias the first pistons132A-D towards deactivated positions, and second return springs138A-D bias the second pistons134A-D towards deactivated positions. Generally speaking, the modular actuators124A-D ofFIG. 5can be structurally identical to one another and, in at least some embodiments, can take on any of the various forms, optional configurations, and functional alternatives described above with respect to the directional drilling system100exemplified inFIGS. 3 and 4(and vice versa).

Hydraulic control systems, each of which is respectively designated at150A,150B,150C and150D inFIG. 7, is contained within and, in some embodiments, fluidly sealed inside each cartridge128A-D. Also contained within and, in some embodiments, fluidly sealed inside the cartridge128A-D is a fluid reservoir152A-D (or “compensated oil volume”). The hydraulic control system150A-150D fluidly couples the fluid reservoir152A-D to the pistons132A-D,134A-D, and regulates the flow of fluid therebetween. In some non-limiting examples, each hydraulic control system150A-150D ofFIG. 7includes hydraulic conduits154A-D for fluidly connecting the individual components of the hydraulic control system150A-150D and distributing hydraulic fluid therebetween. A pump156A-D, which includes the pump piston132A-C, is configured to move the fluid and thereby increase fluid pressure on the actuator piston134A-C. Unidirectional inlet and exhaust valves166A-D (e.g., poppet valves) are disposed between the pump pistons132A-D and the fluid reservoirs152A-D.

The hydraulic control systems150A-150D are configured to regulate or otherwise control movement of the actuator pistons134A-D between respective deactivated and activated positions to thereby change the direction of the drill string100, for example, as described above with respect toFIGS. 3 and 4. According to the illustrated embodiment, each hydraulic control system150A-150D includes a pressure relief valve158A-D (e.g., regulated to a system maximum pressure), and an accumulator/compensator162A-D configured to reduce or otherwise remove hydrostatic pressure. A pulse width modulation (PWM) valve assembly164A-D, which may be in the nature of a PWM poppet valve metering configuration with high-to-low pressure bleed, can be employed to control fluid pressure on the actuator pistons134A-D. PWM techniques can be employed to operate a single-acting solenoid valve controlled bleed to tank, and subsequently the system pressure and travel of the actuator pistons134A-D. In alternative configurations, multi-way directional control valves or other known means can be employed to control fluid pressure. In at least some embodiments, the modular actuators124A-D are characterized by a lack of a fluid coupling to the drill-pipe section of the drill string100to receive drilling fluid therefrom. In this vein, while all of the actuators124A-D engage the drive shaft118for effectuating directional changes to the drill string100, the hydraulic control systems150A-D can be operated independently of each other.

The drill string system100further comprises an actuator steering mechanism and electronics packages, schematically represented herein by the steering controller (or “brain”)160ofFIG. 7. Each modular actuator124A-D includes a respective electrical connector (or “cluster”)168A-D that receives signals for and/or transmits signals from the cartridge128A-D. The electrical connectors168A-D, which may include multi-socket electrical pigtail connectors, banded contacts, wireless communications, and/or other known connectors, operates to electrically couple the modular actuators124A-D, namely the hydraulic control systems150A-D, with the steering controller160. By way of non-limiting example, each electrical connector168A-D provides PWM POWER and PWM GROUND to the PWM valve assembly164A-D, and also provides POT SIGNAL communication as well as POT POWER and POT GROUND to a positional sensor170A-170C. The positional sensor may be in the nature of a linear potentiometer that is integrated into the cartridge128A-D and configured relay or otherwise emit signals indicative of positional feedback data associated with the drill string100.

Packaging each of the components necessary to effect a complete actuator into a single cartridge and utilizing an external “brain” to electrically control the status of the actuator provides a number of benefits over prior art rotary steerable systems. For instance, at least some of the configurations disclosed herein permit service of the hydraulic steering system at the rig site without having to expose the actuator hydraulics to the environment. The introduction of a new/replacement cartridge can quickly and easily return the function of the steering tool to “as new” condition. In addition, standardization of the cartridge can provide the opportunity for reduced inventory variety, optimization of the cartridge design, and the potential for a complete vendor-provided sealed package that is oil filled, tested, and ready to install.