ACTUATOR WITH MOVABLE CYLINDER FOR ROTARY STEERABLE SYSTEM

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application No. 63/710,169 filed on Oct. 22, 2024 which is also incorporated by reference in its entirety.

BACKGROUND

Boreholes may be created for a variety of purposes, including for use as a fluid conduit to access subterranean deposits. A drilling operation may be utilized to construct one or more boreholes to access those subterranean deposits. During the construction of a borehole, it may be necessary to steer the drill bit along as desired path. Accordingly, one or more components on a drillstring may be used to steer the drill bit when drilling.

BRIEF DESCRIPTION OF DRAWINGS

These drawings illustrate certain aspects of some examples of the present disclosure and should not be used to limit or define the disclosure.

FIG. 1 is a diagram of an example drilling environment.

FIG. 2A is a diagram of an example bottom-hole assembly.

FIG. 2B is a diagram of an example bottom-hole assembly.

FIG. 2C is a diagram of an example bottom-hole assembly.

FIGS. 3A-3B are perspective illustrations of different embodiments of steering actuators that comprise a movable cylinder with stationary pistons.

FIG. 4A is a section view of a steering actuator taken through the center axis of the piston and showing the cylinder in a compressed, closed, or unexpanded state.

FIG. 4B is a section view of the steering actuator of FIG. 4A showing the cylinder in an uncompressed, open, or expanded state.

FIG. 5A is a section view of the steering actuator of FIG. 4A showing a channel for mud flow through the piston.

FIG. 5B is a section view of the steering actuator of FIG. 4A showing the mud flow through the steering actuator

FIG. 6A is a section view of a steering actuator taken through the center axis of the piston and showing a flapper pad hingedly fastened to the cylinder where the cylinder is in a compressed, closed, or unexpanded state.

FIG. 6B is a section view of the steering actuator shown in FIG. 6A where the cylinder is in an uncompressed, open, or expanded state.

FIG. 7A is a section view of a steering actuator where slots are used to connect a flapper pad with extensions from the cylinder.

FIG. 7B is a section view of the steering actuator of FIG. 7A where the cylinder is in a compressed, closed, or unexpanded state.

FIG. 7C is a section view of the steering actuator of FIG. 7A where the cylinder is in an uncompressed, open, or expanded state.

DETAILED DESCRIPTION

In general, this application discloses one or more embodiments for the utilization of steering actuators on a Rotary Steerable System (RSS). Specifically, steering actuators that comprise a movable cylinder with stationary or movable stationary pistons. The actuators discussed below may allow for greater flexibility for designing a mandrel and the placement of actuators on the mandrel. Further, the actuators discussed below may be utilized on any existing RSS, effectively providing an upgrade to any current RSS.

Disclosed herein are various types of steering actuators having a stationary piston, a cylinder encircling a portion of the stationary piston and moving relative to the stationary piston, and an inner surface of the cylinder which faces the stationary piston, wherein the cylinder moves away from the stationary piston when mud flows out of the piston to contact the inner surface of the cylinder.

Further steering actuators wherein the cylinder contacts the walls of the borehole when actuated by hydraulic pressure. Further steering actuators comprising a cutout in the cylinder, and a stopper pin positioned within the cutout. Further steering actuators wherein the stopper pin controls a stroke length of the cylinder. Further steering actuators comprising a skirt of the cylinder having an inner surface, and a sleeve positioned on the inner surface. Further steering actuators wherein the cylinder contacts the sleeve as the cylinder moves. Further steering actuators wherein the seal between the cylinder and the sleeve is a metal to metal seal. Further steering actuators wherein mud flows between the cylinder and the sleeve. Further steering actuators comprising a flapper pad hingedly connected to the cylinder.

Disclosed herein are various types of steering actuators having a stationary piston, a cylinder positioned above the stationary piston and moving relative to the stationary piston, and an inner surface of the cylinder which faces the stationary piston, and a valley positioned at the bottom of the cylinder, wherein mud enters the cylinder through the piston, flows between the inner surface of the cylinder and the stationary piston, and exits through the valley.

Further steering actuators wherein the cylinder directly contacts the walls of the borehole. Further steering actuators comprising a flapper pad hingedly connected to the cylinder. Further steering actuators comprising a flapper pad connected to the cylinder through a slot. Further steering actuators comprising a flapper pad hingedly connected to the cylinder. Further steering actuators comprising an extension which extends outwardly from a top surface of the cylinder. Further steering actuators wherein the extension is sized to fit within a slot in the flapper pad.

Disclosed herein are various methods for operating a steering actuator comprising pumping a fluid through a stationary piston, contacting an interior surface of a cylinder with said fluid to cause the cylinder to move away from the stationary piston, and allowing fluid to flow between the piston and the interior surface of the cylinder until exiting by flowing around the cylinder. Further methods comprising contacting the cylinder with a stopper pin to stop the movement of the cylinder. Further methods comprising allowing the cylinder to tilt relative to the piston. Further methods comprising hinging a flapper pad to the cylinder such that movement of the cylinder causes a movement of the flapper pad.

FIG. 1 is a diagram of an example drilling environment. Drilling environment 100 may include drilling platform 102 that supports derrick 104 having a traveling block 108 for raising and lowering top drive 110 and drillstring 114. Top drive 110 supports and rotates drillstring 114 as it is lowered through wellhead 112. In turn, drill bit 124, located at the end of drillstring 114, may create borehole 116. Each of these components is described below.

Platform 102 is a structure which may be used to support one or more other components of drilling environment 100 (e.g., derrick 104). Platform 102 may be designed and constructed from suitable materials (e.g., concrete) which are able to withstand the forces applied by other components (e.g., the weight and counterforces experienced by derrick 104). In any embodiment, platform 102 may be constructed to provide a uniform surface for drilling operations in drilling environment 100.

Derrick 104 is a structure which may support, contain, and/or otherwise facilitate the operation of one or more pieces of the drilling equipment. In any embodiment, derrick 104 may support crown block 106, traveling block 108, and/or any part connected to (and including) drillstring 114. Derrick 104 may be constructed from any suitable materials (e.g., steel) to provide the strength necessary to support those components.

Crown block 106 is one or more simple machine(s) which may be rigidly affixed to derrick 104 and include a set of pulleys (e.g., a “block”), threaded (e.g., “reeved”) with a drilling line (e.g., a steel cable), to provide mechanical advantage. Crown block 106 may be disposed vertically above traveling block 108, where traveling block 108 is threaded with the same drilling line.

Traveling block 108 is one or more simple machine(s) which may be movably affixed to derrick 104 and include a set of pulleys, threaded with a drilling line, to provide mechanical advantage. Traveling block 108 may be disposed vertically below crown block 106, where crown block 106 is threaded with the same drilling line. In any embodiment, traveling block 108 may be mechanically coupled to drillstring 114 (e.g., via top drive 110) and allow for drillstring 114 (and/or any component thereof) to be lifted from (and out of) borehole 116. Both crown block 106 and traveling block 108 may use a series of parallel pulleys (e.g., in a “block and tackle” arrangement) to achieve significant mechanical advantage, allowing for the drillstring to handle greater loads (compared to a configuration that uses non-parallel tension). Traveling block 108 may move vertically (e.g., up, down) within derrick 104 via the extension and retraction of the drilling line.

Top drive 110 is a machine which may be configured to rotate drillstring 114. Top drive 110 may be affixed to traveling block 108 and configured to move vertically within derrick 104 (e.g., along with traveling block 108). In any embodiment, the rotation of drillstring 114 (caused by top drive 110) may cause drillstring 114 to form borehole 116. Top drive may use one or more motor(s) and gearing mechanism(s) to cause rotations of drillstring 114. In any embodiment, a rotatory table (not shown) and a “Kelly” drive (not shown) may be used in addition to, or instead of, top drive 110.

Wellhead 112 is a machine which may include one or more pipes, caps, and/or valves to provide pressure control for contents within borehole 116 (e.g., when fluidly connected to a well (not shown)). In any embodiment, during drilling, wellhead 112 may be equipped with a blowout preventer (not shown) to prevent the flow of higher-pressure fluids (in borehole 116) from escaping to the surface in an uncontrolled manner. Wellhead 112 may be equipped with other ports and/or sensors to monitor pressures within borehole 116 and/or otherwise facilitate drilling operations.

Drillstring 114 is a machine which may be used to form borehole 116 and/or gather data from borehole 116 and the surrounding geology. Drillstring 114 may include one or more drillpipe(s), one or more repeater(s) 120, and bottom-hole assembly 118. Drillstring 114 may rotate (e.g., via top drive 110) to form and deepen borehole 116 (e.g., via drill bit 124) and/or via one or more motor(s) attached to drillstring 114.

Borehole 116 is a hole in the ground which may be formed by drillstring 114 (and one or more components thereof). Borehole 116 may be partially or fully lined with casing to protect the surrounding ground from the contents of borehole 116, and conversely, to protect borehole 116 from the surrounding ground.

Bottom-hole assembly 118 is a machine which may be equipped with one or more tools for creating, providing structure, and maintaining borehole 116, as well as one or more tools for measuring the surrounding environment (e.g., measurement while drilling (MWD), logging while drilling (LWD)). In any embodiment, bottom-hole assembly 118 may be disposed at (or near) the end of drillstring 114 (e.g., in the most “downhole”portion of borehole 116).

Non-limiting examples of tools that may be included in bottom-hole assembly 118 include a drill bit (e.g., drill bit 124), casing tools (e.g., a shifting tool), a plugging tool, a mud motor, a drill collar (thick-walled steel pipes that provide weight and rigidity to aid the drilling process), actuators (and stationary pistons attached thereto), a rotary steerable system, and any measurement tool (e.g., sensors, probes, particle generators, etc.).

Further, bottom-hole assembly 118 may include a telemetry sub to maintain a communications link with the surface (e.g., with information handling system 130). Such telemetry communications may be used for (i) transferring tool measurement data from bottom-hole assembly 118 to surface receivers, and/or (ii) receiving commands (from the surface) to bottom-hole assembly 118 (e.g., for use of one or more tool(s) in bottom-hole assembly 118).

Non-limiting examples of techniques for transferring tool measurement data (to the surface) include mud pulse telemetry and through-wall acoustic signaling. For through-wall acoustic signaling, one or more repeater(s) 120 may detect, amplify, and re-transmit signals from bottom-hole assembly 118 to the surface (e.g., to information handling system 130), and conversely, from the surface (e.g., from information handling system 130) to bottom-hole assembly 118.

Repeater 120 is a device which may be used to receive and send signals from one component of drilling environment 100 to another component of drilling environment 100. As a non-limiting example, repeater 120 may be used to receive a signal from a tool on bottom-hole assembly 118 and send that signal to information handling system 130. Two or more repeaters 120 may be used together, in series, such that a signal to/from bottom-hole assembly 118 may be relayed through two or more repeaters 120 before reaching its destination.

Transducer 122 is a device which may be configured to convert non-digital data (e.g., vibrations, other analog data) into a digital form suitable for information handling system 130. As a non-limiting example, one or more transducer(s) 122 may convert signals between mechanical and electrical forms, enabling information handling system 130 to receive the signals from a telemetry sub, on bottom-hole assembly 118, and conversely, transmit a downlink signal to the telemetry sub on bottom-hole assembly 118. In any embodiment, transducer 122 may be located at the surface and/or any part of drillstring 114 (e.g., as part of bottom-hole assembly 118).

Drill bit 124 is a machine which may be used to cut through, scrape, and/or crush (i.e., break apart) materials in the ground (e.g., rocks, dirt, clay, etc.). Drill bit 124 may be disposed at the frontmost point of drillstring 114 and bottom-hole assembly 118. In any embodiment, drill bit 124 may include one or more cutting edges (e.g., hardened metal points, surfaces, blades, protrusions, etc.) to form a geometry which aids in breaking ground materials loose and further crushing that material into smaller sizes. In any embodiment, drill bit 124 may be rotated and forced into (i.e., pushed against) the ground material to cause the cutting, scraping, and crushing action. The rotations of drill bit 124 may be caused by top drive 110 and/or one or more motor(s) located on drillstring 114 (e.g., on bottom-hole assembly 118).

Pump 126 is a machine that may be used to circulate drilling fluid 128 from a reservoir, through a feed pipe, to derrick 104, to the interior of drillstring 114, out through drill bit 124 (through orifices, not shown), back upward through borehole 116 (around drillstring 114), and back into the reservoir. In any embodiment, any suitable pump 126 may be used (e.g., centrifugal, gear, etc.) which is powered by any suitable means (e.g., electricity, combustible fuel, etc.).

Drilling fluid 128 is a liquid which may be pumped through drillstring 114 and borehole 116 to collect drill cuttings, debris, and/or other ground material from the end of borehole 116 (e.g., the volume most recently hollowed by drill bit 124). Further, drilling fluid 128 may provide conductive cooling to drill bit 124 (and/or bottom-hole assembly 118). In any embodiment, drilling fluid 128 may be circulated via pump 126 and filtered to remove unwanted debris.

Information handling system 130 is a computing system which may be operatively connected to drillstring 114 (and/or other various components of the drilling environment). In any embodiment, information handling system 130 may utilize any suitable form of wired and/or wireless communication to send and/or receive data to and/or from other components of drilling environment 100. In any embodiment, information handling system 130 may receive a digital telemetry signal, demodulate the signal, display data (e.g., via a visual output device), and/or store the data. In any embodiment, information handling system 130 may send a signal (with data) to one or more components of drilling environment 100 (e.g., to control one or more tools on bottom-hole assembly 118).

FIG. 2A is a diagram of an example bottom-hole assembly. Bottom-hole assembly 118 may include a rotary steerable system 242 to control drilling direction 240 of drill bit 124. Each of these components is described below.

Drilling direction 240 is the direction in which drill bit 124 (and/or bottom-hole assembly 118) is oriented to create borehole 116. Drilling direction 240 may be changed via rotary steerable system 242, using one or more steering actuator(s) 246.

Rotary steerable system 242 is a mechanism which may control drilling direction 240. In any embodiment, rotary steerable system 242 may be coupled to one or more components of drillstring 114 via bottom-hole assembly 118. Rotary steerable system 242 may function by utilizing one or more steering actuator(s) 246 to push against the side(s) of borehole 116 to cause changes in the orientation of drill bit 124 (and/or bottom-hole assembly 118). When steering actuator(s) 246 press against the walls of borehole 116, bottom-hole assembly 118 is subjected to a counteracting force which may cause a torque that pivots drill bit 124 away from an existing drilling direction 240 to a new drilling direction 240 (e.g., a “push-the-bit” system for directional drilling).

In any embodiment, rotary steerable system 242 may function while bottom-hole assembly 118 is rotating. To cause the deflection of drilling direction 240 in a (relatively) consistent direction, steering actuator(s) 246 may be extended only while facing the appropriate direction. That is, as all steering actuator(s) 246 are rotating with bottom-hole assembly 118, steering actuator(s) 246 may be extended only for the portion of time in which they are facing the direction opposite the desired drilling direction 240. Thus, steering actuator(s) 246 may be repeatedly extended and retracted—as bottom-hole assembly 118 rotates—to effectuate the desired change in drilling direction 240.

As a non-limiting example, for simplicity, consider a two-dimensional environment where bottom-hole assembly 118 has a drilling direction 240 due “rightward”. Then, to avoid an obstacle, it is desired to have drill bit 124 change to a slightly “downward” (but still mostly rightward) drilling direction 240. To cause this change, steering actuator(s) 246 that face “upward” (i.e., the direction opposite downward) are extended to push drill bit 124 downward. Once the desired drilling direction 240 is achieved, steering actuator(s) 246 remain retracted as no further change in drilling direction 240 is needed.

Steering controller 243 is a mechanism which may control the operation of one or more steering actuator(s) 246 to achieve the desired change in drilling direction 240. Steering controller 243 may be a computing device (e.g., like information handling system 130) which includes a processor, memory, storage, interface device(s), etc. Steering controller 243 may utilize electronic means for controlling steering actuator(s) 246 (e.g., via electrical actuation) and/or via mechanical means for controlling steering actuator(s) 246 (e.g., via hydraulic actuation). Steering controller 243 may control the timing of the extension and retraction of steering actuator(s) 246—as bottom-hole assembly 118 rotates—such that drill bit 124 is deflected to the to the desired drilling direction 240.

Actuator row 244 is an arrangement of two or more steering actuators 246 disposed circumferentially around bottom-hole assembly 118, in a plane that is substantially orthogonal (i.e., perpendicular) to drilling direction 240. As shown in the example of FIG. 2A, steering actuator(s) 246, within one actuator row 244, may be disposed to not align with (i.e., be at a radial offset from) steering actuator(s) 246 in another actuator row 244 (in drilling direction 240). That is, as shown in the example of FIG. 2A, steering actuator(s) 246 are at a radial offset (depicted as horizontal offsets in the two-dimensional example of FIG. 2A) from other steering actuator(s) 246 in the vertical direction (e.g., a vertical line cannot be drawn through two steering actuators 246). In any embodiment, steering actuator(s) 246 in actuator row 244 may be disposed uniformly around a circumference of bottom-hole assembly 118.

As a non-limiting example, as shown in FIG. 2A, a rotary steerable system 242 may include three actuator rows 244. Each actuator row 244 may include five steering actuators 246, for a total of fifteen steering actuators 246 (only seven steering actuators 246 are visible in FIG. 5A). Within a single actuator row 244, the three steering actuators 246 may be disposed 72° apart around the body of bottom-hole assembly 118. Then, the three actuator rows 244 may be arranged in a radial offset of 24° from each other. Thus, steering actuators 246 are disposed every 24° around the body of bottom-hole assembly 118 (e.g., when bottom-hole assembly 118 is viewed head-on, in drilling direction 240). Accordingly, in such an example, finer control of drilling direction 240 may be achieved through use of the distributed steering actuators 246 (e.g., over a 12° (±6°) arc).

FIG. 2B is a diagram of an example bottom-hole assembly. Bottom-hole assembly 118 may include drill bit 124, one or more steering actuator(s) 246, configured for actuator movement 249 during rotation 248.

In the example of FIG. 2B, steering actuator(s) 246 are in the form of a cylinder pad which has a linear actuator movement 249 orthogonal to an exterior curved surface of bottom-hole assembly 118. Similar to the example shown in FIG. 2A, in any embodiment, there may be three actuator row(s) 244 with steering actuator(s) 246 disposed at a radial offset from each other around a circumference of bottom-hole assembly 118.

FIG. 2C is a diagram of an example bottom-hole assembly. Bottom-hole assembly 118 may include drill bit 124, one or more steering actuator(s) 246, configured for actuator movement 249 during rotation 248.

In the example of FIG. 2C, steering actuator(s) 246 are in the form of hinged pads which have an actuator movement 249 that pivots away from the surface of bottom-hole assembly 118. As shown in the example of FIG. 3C, in any embodiment, there may be two actuator row(s) 244 with steering actuator(s) 246 which are arranged at a radial offset from each other around a circumference of bottom-hole assembly 118.

FIG. 3A illustrates an RSS 242 comprising a mandrel 300 and a plurality of steering actuators 246 disposed axially along mandrel 300. RSS 242 in FIG. 3A illustrates current technology in which steering actuators 246, stationary piston pads, are disposed in mandrel 300 and held within mandrel 300 by a locking collar 302 and one or more fastening elements 304. It should be noted that, due to locking collar 302, steering actuators 246 are reduced in size and/or diameter as compared to steering actuators 246, cylinder pads, in FIG. 3B. Further, fastening elements 304 may attach locking collar 302 to mandrel 300 using threaded connections. Threaded connections, due to flex experienced by RSS 242 in a downhole environment, may crack under stress. This may lead to failure of locking collar 302 and subsequently steering actuator 246. In a cylinder pad arrangement, the top surface of the cylinder is the push pad, in direct contact with formation, compared to stationary piston pads in FIG. 3A. Additionally, with continued reference to FIG. 3A, surface 306 of a cylinder pad may be much larger than the diameter of a stationary piston pad. Thus, a cylinder pad has a larger amount of formation contact pressure when compared to the stationary piston pad. Additionally, a cylinder pad may be non-circular, such as oval, rectangular, and/or the like. Due to locking collar 302, stationary piston pads in FIG. 3A remain circular due to space available on mandrel 300. More pad surface, found on cylinder pads, may provide space to add features such as flanks, lateral protections (PDC pucks on the downhole/uphole side of the cylinder pad), etc. Pad stopper is easier/simpler to implement on the cylinder than on the stationary piston.

FIG. 4A illustrates a lateral cross-section view of steering actuator 246, cylinder pad. In FIG. 4A, steering actuator 246 is in a closed, or unexpanded, state. As illustrated, steering actuator 246 may comprise a stationary piston 400, retained and connected to collar 406 of mandrel 300 (E.g., referring to FIG. 3) by a stationary piston retainer 402. In examples, stationary piston 400 may be formed of hardened materials, such as tungsten carbide or harder material. This may allow stationary piston 400 to resist abrasion from the corrosive environment in which stationary piston 400 may operate and function. As stationary piston retainer 402 receives less wear, stationary piston retainer 402 may be formed of steel material.

During installation, stationary piston retainer 402 may hold stationary piston 400 in place by pressing flange 404 of stationary piston 400 against collar 406, using rim 408. Collar 406 is defined as all surfaces within void 407 of mandrel 300 in which steering actuator 246 may be disposed. As illustrated, stationary piston retainer 402 may have a plurality of threading 410 which may mate with collar threading 412. Stationary piston retainer 402 may be spun in using a tool that seats into key 414, allowing torque to be applied to stationary piston retainer 402. It should be noted that key 414 may be a void in stationary piston retainer 402 that is at least a part of channel 416. Channel 416 may further connect to pathway 418. Pathway 418 may allow for mud to flow to channel 416, through key 414 and apply force to cylinder 420 at inner surface 422 of cylinder 420.

FIG. 4B illustrates an open, or expanded, state of steering actuator 246. As mud flows out of key 414, as described above, and presses into inner surface 422 of cylinder 420, cylinder 420 may rise by moving away from stationary piston retainer 402. The lateral movement of cylinder 420 in a vertical direction is called the “stroke.” The length of the stroke is controlled by stopper pins 424 that may be connected to a part of collar 406. Further, stopper pins 424 may be disposed through skirt 426 of cylinder 420. Skirt 426 of cylinder 420 may be of any thickness to allow for and diameter of stopper pins 424. As illustrated in FIGS. 4A and 4B, cut-out 428 of skirt 426 may control the stroke length of cylinder 420. The longer cut-out 428 within skirt 426 is, the longer the stroke of cylinder 420 may be. In examples, the top of the stroke may be when stopper pins 424 contact lower surface 430 of cut-out 428. The bottom of the stroke may be when stopper pins contact upper surface 432 of cut-out 428. With continued reference to FIGS. 4A and 4B, skirt 426 may comprise an inner surface 434 removed in which a sleeve 436 may be disposed. Sleeve 436 may be of a hardened metal such as tungsten. In examples, sleeve 436 may be shrink fitted into inner surface 434.

FIGS. 5A and 5B illustrate the flow of mud 500 during operations in which cylinder 420 is forced upward during a stroke based at least in part on the flow of mud 500. The cylinder 420 may be forced upward to contact the walls of the borehole when actuated by hydraulic pressure from a fluid flow (drilling fluid or mud). As discussed above, pathway 418 may allow for mud 500 to flow to channel 416, through key 414 and apply force to cylinder 420 at inner surface 422 of cylinder 420. As mud 500 pushed cylinder 420 to the top of the stroke, as noted above, stopper pins 424 may prevent skirt 426 from moving any further, which prevents cylinder 420 from moving any further. At the top of the stroke, with mud 500 continuing to move into chamber 502, pressure forces mud to flow between sleeve 436 and stationary piston 400. Stationary piston 400 and sleeve 436 form a metal-on-metal seal, which is not fluid tight. This allows for mud 500 to escape from chamber 502 between stationary piston 400 and sleeve 436. A valley 504 allows for mud 500 to move around sleeve 436 and around the outer surface 406 of skirt 426. Space 506 may allow mud 500 to move between collar 406 and skirt 426 to outside of mandrel 300 and into an annulus. It should be noted that valley 504, which cylinder 420 is compressed back into a closed, or unexpanded state, may provide tolerance and room for mud 500 to move between space 506 and between sleeve 436 and outer surface 406 as skirt 426 move back toward the bottom of collar 406. Thus, valley 504 prevents skirt 426, and as such cylinder 420, from getting stuck in the downward stroke.

FIGS. 6A and 6B illustrate steering actuator 246 in which cylinder 420 moves at an angle and may be connected to flapper pad 600 through hinge 606. Steering actuator 246 may operate and function generally as described above. However, as illustrated in FIGS. 6A and 6B, stationary piston 400 may be rounded at any suitable angle at upper edge 602 and lower edge 604. This may allow for cylinder 420 to pivot at an angle, as illustrated in FIG. 4B, to extend flapper pad 600. Attached to flapper pad 600 at hinge 606, cylinder 420 may rotate about hinge 606 during an upper stroke. The pivoting of cylinder 420 may be caused due to flapper pad 600 being attached to pin 608 at an opposite end of flapper pad 600. Pin 608 may attach flapper pad 600 to collar 406. Thus, as cylinder 420 expands to the limits of its upper stroke, flapper pad 600 rotates about pin 608, which may cause cylinder 420 to pivot. The pivoting cylinder 420 may also be allowed as space 506 between skirt 426 and collar is increased. This may allow tolerance for cylinder 420 to pivot without skirt 426 touching the surfaces of collar 406. Even further, an angled ridge 610 at the top of collar 406 may allow for cylinder 420 to pivot toward pin 608.

FIG. 7A is a section view of a steering actuator where a slot 700 may be used to connect a flapper pad 600 with extensions 702 from the cylinder 420. In some embodiments, two or more cylinders 420 may be connected to a single flapper pad 600.

FIG. 7B is a section view of the steering actuator of FIG. 7A where the cylinder is in a compressed, closed, or unexpanded state. It should be noted that steering actuator 246 may operate and function as described above. In this example, cylinder 420 may comprise at least in part extensions 702 that extend outward from top 704 of cylinder 420. Extensions 702 may mate with slot 700.

FIG. 7C is a section view of the steering actuator of FIG. 7A where the cylinder is in an uncompressed, open, or expanded state. As illustrated, specifically, extensions 702 may slide within slot 700. Without limitation, extensions 702 may lock in place within slot 700. Further, although illustrated to show that extensions 702 slide within slot 700, extensions 702 may mate to slot 700 by any suitable means. Through extensions 702, cylinder 420 may be rigidly mated to flapper pad 600. Thus, cylinder 420 may pivot more within space 506, due to the ridged connection between flapper pad 600 and cylinder 420. As illustrated, space 506 may be larger than previous examples disclosed above. The increased width and/or length of space 506 may remove the utilization of angled rim 610 (e.g., referring to FIG. 6).

Improvements utilizing the examples above may be found in that the cylinder does not need additional retention, the cylinder does not need additional seal (face seal, radial seal etc.) and the cylinder may be constructed of hard material shrink fit into more rugged metal sleeve with low cost. Further, when integrated as a pad, the cylinder may have larger contact surface to formation than a pad with integrated stationary piston. Further, this may allow for the collar to have more material for strength since pad housing for cylinder retention is no longer needed. Additionally, pad housing and pad bolts do not have to overcome hydraulic force acting on cylinder during normal operation.