Patent Publication Number: US-11649680-B2

Title: Push the bit rotary steerable system

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a continuation of U.S. patent application Ser. No. 15/999,107, filed Aug. 17, 2018, which is a national phase application under 35 U.S.C. § 371 of International Patent Application PCT Application No. PCT/IB2017/000233, filed Feb. 20, 2017, which is a continuation of Ser. No. 15/046,963, filed Feb. 18, 2016, now U.S. Pat. No. 9,624,727. The entire contents of the foregoing applications are incorporated herein by reference. 
    
    
     TECHNICAL FIELD 
     The present disclosure relates generally to a rotary steerable tool and more particularly to systems, methods, and devices for pushing a drill bit using a downhole actuation system. 
     BACKGROUND 
     Field formations can include reservoirs holding one or more resources. To reach such reservoirs so that the resources can be extracted, one or more holes are drilled through the field formations. Various drilling techniques can be used when creating a wellbore in an exploration process. 
     One or more such techniques involve the use of rotary steerable tools. Rotary steerable tools are used to direct the path of wellbores when drilling for resources. One application in which rotary steerable tools are used is when an entity is drilling multiple wells in different directions from one location. Another application in which rotary steerable tools are used is when an entity is positioning a wellbore horizontally along the length of a reservoir to maximize the amount of resources collected. 
     SUMMARY 
     In general, in one aspect, the disclosure relates to a method for pushing a rotary drill bit. The method can include receiving a target direction in a formation to push the rotary drill bit while drilling a wellbore in a formation. The method can also include opening, at a first rotational position of a rotary bit pushing device disposed proximate to the rotary drill bit within the wellbore, a first inlet port of a first flow regulator, where the first inlet port, when in an open position, allows a first quantity of drilling fluid to move a first deflection device of a plurality of deflection devices of the rotary bit pushing device from a normal position to an extended position, where the first deflection device, when in the extended position, contacts the formation bounding the wellbore. The method can further include closing, after the first rotational position of the rotary bit pushing device, the first inlet port, where the first inlet port, when in a closed position, stops the first quantity of drilling fluid from flowing to the first deflection device and allows the first deflection device to return to the normal position. The method can also include sending, to a second flow regulator of the rotary bit pushing device, a second quantity of drilling fluid, where the second quantity of drilling fluid flows to the first deflection device when the first flow regulator is in the closed position. At least a portion of the first quantity of drilling fluid can flow through the first deflection device into the wellbore when the first inlet port is in the open position. At least a portion of the second quantity of drilling fluid can flow through the first deflection device into the wellbore when the first inlet port is in the closed position. The first deflection device contacting the formation when the rotary bit pushing device is in the first rotational position can push the rotary drill bit in the target direction. 
     In another aspect, the disclosure relates to a rotary bit pushing device. The device can include a body having at least one wall that forms a cavity, where the at least one wall has at least one aperture that traverses the at least one wall and at least one channel disposed adjacent to the at least one aperture, where the body has a proximal end and a distal end that defines the at least one wall along a length of the body. The device can also include at least one deflection device moveably disposed in the at least one aperture in the at least one wall of the body, where the at least one deflection device moves radially with respect to an axis formed along the length of the body. The device can further include at least one sealing device disposed against the at least one deflection device, where the at least one sealing device is disposed between the at least one channel and the wellbore. The device can also include at least one flow regulator disposed adjacent to the cavity and to the at least one channel, where the at least one flow regulator is configured to allow a first portion of drilling fluid flowing through the cavity of the body to pass into the at least one channel. A second portion of the drilling fluid can flow into the at least one aperture, where the second portion of the drilling fluid is controlled by at least one additional flow regulator that allows the second portion of the drilling fluid to flow into the at least one aperture based on a position of the at least one deflection device relative to a wellbore, where the first portion of the drilling fluid reaches the at least one flow regulator substantially continually. 
     In yet another aspect, the disclosure relates to a push the bit rotary steerable system. The system can include a rotary drill bit, and a drill string having at least one wall that forms a cavity. The system can also include a drilling fluid circulation system that sends drilling fluid through the cavity, and a rotary bit pushing device coupled to a proximal end of the drill string and a proximal end of the rotary drill bit. The rotary bit pushing device can include a body having at least one wall that forms the cavity, where the at least one wall has at least one aperture that traverses the at least one wall and at least one channel disposed adjacent to the at least one aperture. The rotary bit pushing device can also include at least one deflection device disposed in the at least one aperture in the at least one wall of the body. The rotary bit pushing device can further include at least one sealing device disposed around the at least one deflection device, where the at least one sealing device is disposed within the at least one cavity adjacent to the at least one wall of the body, where the at least one sealing device is further disposed between the at least one channel and the wellbore, where the at least one sealing device divides the at least one aperture into a distal portion and a proximal portion, where the proximal portion of the at least one aperture is adjacent to the at least one channel. The rotary bit pushing device can also include at least one flow regulator disposed adjacent to the cavity and to the at least one channel, where the at least one flow regulator is configured to allow a first portion of drilling fluid flowing through the cavity of the body to pass into the at least one channel. A second portion of the drilling fluid can flow into the at least one aperture, where the second portion of the drilling fluid is controlled by at least one additional flow regulator that allows the second portion of the drilling fluid to flow into the at least one aperture based on a position of the at least one deflection device relative to a wellbore, where the first portion of the drilling fluid reaches the at least one flow regulator substantially continually. 
     These and other aspects, objects, features, and embodiments will be apparent from the following description and the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The drawings illustrate only example embodiments and are therefore not to be considered limiting of its scope, as the example embodiments may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positionings may be exaggerated to help visually convey such principles. In the drawings, reference numerals designate like or corresponding, but not necessarily identical, elements. 
         FIG.  1    shows a schematic view, partially in cross section, of a field undergoing exploration using an example push the rotary bit pushing device in accordance with one or more example embodiments. 
         FIG.  2    shows a side view of a bottom hole assembly that includes an example push the rotary bit pushing device in accordance with one or more example embodiments. 
         FIGS.  3 A-C  shows various views of an example rotary bit pushing device in accordance with one or more example embodiments. 
         FIGS.  4 A- 4 D  show various views of a deflection device in accordance with one or more example embodiments. 
         FIGS.  5 A and  5 B  show various views of a sleeve for a deflection device in accordance with one or more example embodiments. 
         FIG.  6    shows a flow control device in accordance with one or more example embodiments. 
         FIG.  7    shows a flow control device assembly in accordance with one or more example embodiments. 
         FIG.  8    is a flowchart presenting a method for pushing a rotary drill bit in accordance with one or more example embodiments. 
         FIG.  9    shows a computer system for implementing pushing a rotary drill bit in accordance with one or more example embodiments. 
     
    
    
     DETAILED DESCRIPTION OF EXAMPLE EMBODIMENTS 
     In general, the example embodiments described herein provide systems, methods, and devices for pushing a rotary drill bit. More specifically, the example embodiments provide for controlling a direction in which a drill bit pushes during an operation (e.g., exploration, production) in a field. For clarification, a field can include part of a subterranean formation. More specifically, a field as referred to herein can include any underground geological formation containing a resource (also called a subterranean resource) that may be extracted. Part, or all, of a field may be on land, water, and/or sea. Also, while a single field measured at a single location is described below, any combination of one or more fields, one or more processing facilities, and one or more wellsites can be utilized. The subterranean resource can include, but is not limited to, hydrocarbons (oil and/or gas), water, steam, helium, and minerals. A field can include one or more reservoirs, which can each contain one or more subterranean resources. 
     When a drill bit is pushed to steer the bottom hole assembly, the drill bit is directed to a target location (also called a target direction) in the wellbore. Because the bottom hole assembly (as well as the entire drill string) is rotating, pushing the drill bit at the target location can be challenging. In other words, the point to which the drill bit is directed is stationary within the wellbore, but the drill bit itself is rotating during the field operation. In some cases, example embodiments can make constant adjustments to keep the drill bit pushed at the target location during the field operation. As defined herein, example embodiments are described as pushing a drill bit, even though example embodiments are located proximate to, but not integral with, the drill bit. Rather, example embodiments push against a particular location along the wall of a wellbore to control the direction of the drill bit. 
     When the bottom hole assembly rotates relative to the target location, there can be a number of rotational positions of the bottom hole assembly (taken radially from the axis along the length of the bottom hole assembly) relative to the target location. The rotational positions can be discrete or continuous. The sum of the rotational positions can cover a full rotation (360°) of the bottom hole assembly. As defined herein, a liquid-tight seal is a barrier that prevents all or a substantial amount of liquid (e.g., drilling fluid, drilling mud) from passing therethrough. In one or more example embodiments, a user is any entity that uses the systems and/or methods described herein. For example, a user may be, but is not limited to, a drilling engineer, a company representative, a manufacturer&#39;s representative, a control system, a contractor, an engineer, a technician, a consultant, or a supervisor. The push the bit rotary steerable systems (or components thereof) described herein can be made of one or more of a number of suitable materials to effectively operate while also maintaining durability in light of the one or more conditions under which the push the bit rotary steerable systems can be exposed. Examples of such materials can include, but are not limited to, aluminum, stainless steel, fiberglass, glass, plastic, ceramic, and rubber. 
     Example push the bit rotary steerable systems, or portions thereof, described herein can be made from multiple pieces that are mechanically coupled to each other. In such a case, the multiple pieces can be mechanically coupled to each other using one or more of a number of coupling methods, including but not limited to epoxy, welding, fastening devices, compression fittings, mating threads, and slotted fittings. One or more pieces that are mechanically coupled to each other can be coupled to each other in one or more of a number of ways, including but not limited to fixedly, hingedly, removeably, slidably, and threadably. 
     Components and/or features described herein can include elements that are described as coupling, mounting, fastening, securing, or other similar terms. Such terms are merely meant to distinguish various elements and/or features within a component or device and are not meant to limit the capability or function of that particular element and/or feature. For example, a feature described as a “coupling feature” can couple, mount, secure, fasten, abut against, and/or perform other functions aside from merely coupling. 
     A coupling feature (including a complementary coupling feature) as described herein can allow one or more components and/or portions of an example push the bit rotary steerable system (e.g., a rotary bit pushing device, a deflection device) to become mechanically coupled, directly or indirectly, to another portion of the push the bit rotary steerable system. A coupling feature can include, but is not limited to, a portion of a hinge, an aperture, a recessed area, a protrusion, a clamp, a slot, a spring clip, a tab, a detent, and mating threads. One portion of an example push the bit rotary steerable system can be coupled to a component of the push the bit rotary steerable system by the direct use of one or more coupling features. 
     In addition, or in the alternative, a portion of an example push the bit rotary steerable system can be coupled to a component of a push the bit rotary steerable system using one or more independent devices that interact with one or more coupling features disposed on a component of the push the bit rotary steerable system. Examples of such devices can include, but are not limited to, a pin, a hinge, a fastening device (e.g., a bolt, a screw, a rivet), a clamp, and a spring. One coupling feature described herein can be the same as, or different than, one or more other coupling features described herein. A complementary coupling feature as described herein can be a coupling feature that mechanically couples, directly or indirectly, with another coupling feature. 
     In the foregoing figures showing example embodiments of push the bit rotary steerable systems, one or more of the components shown may be omitted, repeated, and/or substituted. Accordingly, example embodiments of push the bit rotary steerable systems should not be considered limited to the specific arrangements of components shown in any of the figures. For example, features shown in one or more figures or described with respect to one embodiment can be applied to another embodiment associated with a different figure or description. 
     Further, if a component of a figure is described but not expressly shown or labeled in that figure, the label used for a corresponding component in another figure can be inferred to that component. Conversely, if a component in a figure is labeled but not described, the description for such component can be substantially the same as the description for the corresponding component in another figure. 
     Example embodiments of push the bit rotary steerable systems will be described more fully hereinafter with reference to the accompanying drawings, in which example embodiments of push the bit rotary steerable systems are shown. Push the bit rotary steerable systems may, however, be embodied in many different forms and should not be construed as limited to the example embodiments set forth herein. Rather, these example embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of push the bit rotary steerable systems to those of ordinary skill in the art. Like, but not necessarily the same, elements (also sometimes called components) in the various figures are denoted by like reference numerals for consistency. 
     Terms such as “first”, “second”, “top”, “bottom”, “side”, “width”, “length”, “radius”, “inner”, and “outer” are used merely to distinguish one component (or part of a component or state of a component) from another. Such terms are not meant to denote a preference or a particular orientation, and are not meant to limit embodiments of push the bit rotary steerable systems. In the following detailed description of the example embodiments, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. 
       FIG.  1    is a schematic view, partially in cross section, of a field  100  undergoing exploration using an example push the rotary bit pushing device in accordance with one or more example embodiments. Referring to  FIG.  1   , the field  100  is subterranean and can include a bottom hole assembly  170  that is suspended by a rig  102  at the surface  104  using drill pipe  172  (also called a drill string  172 ) and advanced into the subterranean formation  105  to form a wellbore  130 . The subterranean formation  105  can have a number of geological structures. For example, as shown in  FIG.  1   , the subterranean formation  105  can have a clay layer  121 , a sandstone layer  122 , a limestone layer  123 , a shale layer  127 , a sand layer  125 , and a reservoir  126 . 
     Data acquisition tools and/or sensing devices can be used to measure the subterranean formation  105  and detect the characteristics of the various layers of the subterranean formation  105 . The data collected by data acquisition tools, as well as other data measured by one or more sensing devices located at various locations (e.g., the mud pit  106 , at the surface  104 , on the rig  102 ) in the field  100 , can be gathered and processed by a data acquisition system  101  that is communicably coupled to the various data acquisition tools and/or sensing devices. In certain example embodiments, the data acquisition system  101  can perform other functions with respect to the field data, including but not limited to generating models, and communicating with (generating signals, sending signals, receiving signals) one or more devices in the field  100 , including but not limited to the control device (described below with respect to  FIGS.  3 A-C ). 
     For example, as shown in  FIG.  1   , the data acquisition system  101  can include a controller  103 . In such a case, the controller  103  can control one or more flow regulators (e.g., flow regulator  280  in  FIG.  7   , described below) used with example embodiments. The controller  103  can also coordinate with another portion of the data acquisition system  101  to determine the orientation of an example rotary bit pushing device (described below) in a wellbore at any point in time. The data acquisition system  101 , or any portion thereof, can communicate with one or more devices in the field  100  using a communication link  107 , which can use wired and/or wireless technology. 
     Fluids are circulated in a substantially closed-loop system to assist in the drilling process. Drilling fluid  178  is pumped down the annulus of the drill pipe  172  and the bottom hole assembly  170 . As the drill bit at the end of the bottom hole assembly  170  cuts into the subterranean formation  105 , pieces of the subterranean formation  105  are mixed in with the drilling fluid  178  to create drilling mud  180  within the wellbore between the subterranean formation  105  and the outside of the drill pipe  172  and bottom hole assembly  170 . The drilling mud  180  is drawn back to the surface  104  to a mud pit  106  via a flow line  108 . 
     The mud pit  106  filters the drilling mud  180 , removing the larger bits (e.g., rock) of the subterranean formation  105 , to return the fluid to drilling fluid  178 , which is again pumped down the annulus of the drill pipe  172 . The bottom hole assembly  170  is advanced into the subterranean formation to reach a reservoir  126 . Each well can target one or more reservoirs  126 . The bottom hole assembly  170  can be adapted for measuring downhole properties using logging while drilling (LWD) tools, measurement while drilling (MWD) tools, and/or any other suitable measuring tool (also called data acquisition tools). 
     The data acquisition tools can be integrated with the bottom hole assembly  170  and generate data plots and/or measurements. These data plots and/or measurements are depicted along the field  100  to demonstrate the data generated by the various operations. While only a simplified configuration of the field  100  is shown, it will be appreciated that the field  100  can cover a portion of land, sea, and/or water locations that hosts one or more wellsites. Production can also include one or more other types of wells (e.g., injection wells) for added recovery. One or more gathering facilities can be operatively connected to one or more of the wellsites for selectively collecting downhole fluids and/or resources from the wellsite(s). 
     Further, while  FIG.  1    describes data acquisition tools and/or sensing devices used to measure properties of a field, it will be appreciated that the tools and/or devices can be used in connection with non-wellsite operations, such as mines, aquifers, storage, or other subterranean facilities. Also, while certain data acquisition tools (e.g., bottom hole assembly  170 , data acquisition system  101 ) are depicted, it will be appreciated that various other measurement tools (e.g., sensing parameters, seismic devices) measuring various parameters of the subterranean formation  105  and/or its geological formations can be used. Various sensors can be located at various positions along the wellbore and/or as part of the monitoring tools to collect and/or monitor the desired data. Other sources of data can also be provided from offsite locations. 
     When a data acquisition tool and/or other device (e.g., the controller  103 ) is incorporated with the bottom hole assembly  170 , such tools and/or devices can communicate with the data acquisition system  101  and/or controller  103  in one or more of a number of ways. The data acquisition system  101  and/or controller  103  can communicate with a data acquisition tool and/or a measuring device using wired and/or wireless technology. As an example of using a wireless technology, the data acquisition system  101  and/or controller  103  can communicate with a downhole tool and/or device using energy waves that are transported through the drilling fluid  178  during a field operation. 
       FIG.  2    shows a side view of a bottom hole assembly  170  that includes an example rotary bit pushing device  220  in accordance with one or more example embodiments. Referring now to  FIGS.  1  and  2   , the bottom hole assembly  170  of  FIG.  2    includes a drill collar  210  positioned between an upper sleeve stabilizer  212 , and the push the rotary bit pushing device  220 . The bottom hole assembly  170  also includes a drill bit assembly  230  located at the end of the bottom hole assembly  170 , below the push the rotary bit pushing device  220 . Another drill collar  211  can also be located on the opposite side of (further uphole from) the upper stabilizer  212 . 
     The drill collars  210 ,  211  can be pipes of a known inner diameter and outer diameter along a known length and have substantially uniform thickness along the length. The drill collars  210 ,  211  can be made of one or more of a number of suitable materials for the environment in which the field operation is being performed. Examples of such materials can include, but are not limited to, stainless steel and galvanized steel. A cavity, defined by the inner diameter, traverses the length of each drill collar (e.g., drill collar  210 , drill collar  211 ). 
     The upper sleeve stabilizer  212  can mechanically stabilize the bottom hole assembly  170  in the borehole in order to avoid unintentional sidetracking and/or vibrations, and/or to ensure the quality of the hole being drilled. In certain example embodiments, the upper sleeve stabilizer  212  can include a hollow cylindrical body and stabilizing blades disposed on the outer surface of the body, all made of high-strength steel and/or some other suitable material. The blades of the upper sleeve stabilizer  212  can have one or more of a number of shapes, including but not limited to straight and spiraled. The blades can be hardfaced for wear resistance. 
     The upper sleeve stabilizer  212  can be integral (i.e., formed from a single piece of material such as steel) or a composite of multiple pieces mechanically coupled together. An example of the latter case can be an upper sleeve stabilizer  212  where the blades are located on a sleeve, which is then screwed on the body of the upper sleeve stabilizer  212 . Another example of the latter case is an upper sleeve stabilizer  212  where the blades are welded to the body. In certain example embodiments, the bottom hole assembly  170  can include more than one stabilizer located at various points along the bottom hole assembly  170 . For example, as shown in  FIG.  2   , the bottom hole assembly  170  can also include a near bit stabilizer  224  disposed between drill collar  210  and the rotary bit pushing device  220 . 
     The drill collars  210 ,  211 , the stabilizers (e.g., the upper sleeve stabilizer  212 , the near-bit stabilizer  224 ), the drill bit assembly  230 , and/or any other components of the bottom hole assembly  170  are mechanically coupled to each other using one or more of a number of coupling methods. For example, as is common in the industry, such components are coupled to each other using mating threads that are disposed on each end of each component. When such components of the bottom hole assembly  170  are mechanically coupled to each other, the coupling is conducted in such a way as to comply with engineering and operational requirements. For example, when mating threads are used, a proper torque is applied to each coupling. 
     Much of the push the rotary bit pushing device  220  is described below with respect to  FIGS.  3 A- 7   . In  FIG.  2   , most of the push the rotary bit pushing device  220  is hidden from view. The portions of the rotary bit pushing device  220  that are visible in  FIG.  2    (and which are described in more detail below with respect to  FIGS.  3 A- 3 C ) are the deflection devices  240 , the deflection device holders  250 , and the outer surface of the body  221 . 
     The drill bit assembly  230  includes a drill bit  232 , and a drill bit collar  234 . In  FIG.  2   , only the collar  236  of the bit shaft  235  (located at the distal end of the bit shaft  235 ) is shown, while the rest of the bit shaft  235  is hidden from view by the rotary bit pushing device  220 . The bit shaft  235  may be part of, or a separate component that is coupled to, the push the rotary bit pushing device  220 . The bit shaft  235  can have a cavity that traverses along its length. The bit shaft  235  can have multiple features. For example, the collar  236  of the bit shaft  235  can include one or more coupling features (e.g., mating threads) that mechanically couples to the proximal end of the drill bit collar  234 . Similarly, the proximal end of the bit shaft  235  (hidden from view) can include one or more coupling features that allow the bit shaft  235  to couple to another component (e.g., the rotary bit pushing device  220 ) of the bottom hole assembly  170 . 
     The proximal end of the drill bit collar  234  is mechanically coupled to the distal end of the bit shaft  235 , while the distal end of the drill bit collar  234  is mechanically coupled to the drill bit  232 . The drill bit  232  and the drill bit collar  234  can be formed as a single piece (as from a mold) or from multiple pieces that are mechanically coupled to each other using one more of a number of coupling methods, including but not limited to welding, mating threads, and compression fittings. 
     The drill bit  232  is a tool used to crush and/or cut rock. The drill bit  232  is located at the distal end of the bottom hole assembly  170  and can be any type (e.g., a polycrystalline, diamond compact bit, a roller cone bit, an insert bit) of drill bit having any dimensions (e.g., 5 inch diameter, 9 inch diameter, 50 inch diameter) and/or other characteristics (e.g., rotating cones, rotating head, rotating cutters). The drill bit  232  can include one or more of a number of materials, including but not limited to steel, diamonds, and tungsten carbide. 
       FIGS.  3 A-C  shows various views of an example push the rotary bit pushing device  220  in accordance with one or more example embodiments. Specifically,  FIG.  3 A  shows a top-side perspective view of the rotary bit pushing device  220 .  FIG.  3 B  shows an exploded view of the rotary bit pushing device  220 .  FIG.  3 C  shows a cross-sectional side view of the rotary bit pushing device  220 .  FIGS.  4 A- 4 D  shows various views of a deflection device  240  of the rotary bit pushing device  220  in accordance with one or more example embodiments. Specifically,  FIGS.  4 A and  4 B  each shows a top-side perspective view of the deflection device  240 .  FIG.  4 C  shows a bottom-side perspective view of the deflection device  240 .  FIG.  4 D  shows a cross-sectional side view of the deflection device  240 . 
       FIGS.  5 A and  5 B  show a top-side perspective view and a bottom-side perspective view, respectfully, of an inner deflection device sleeve  270  in accordance with one or more example embodiments.  FIG.  6    shows a cross-sectional side view detailing a flow regulator  610  of the rotary bit pushing device  220  in accordance with one or more example embodiments.  FIG.  7    shows a side perspective view of another flow regulator  280  of the rotary bit pushing device  220  in accordance with one or more example embodiments. 
     Referring to  FIGS.  1 - 7   , the rotary bit pushing device  220  can include a number of different components. For example, as shown in  FIGS.  3 A- 3 C , the rotary bit pushing device  220  can include a body  320 , at least one deflection device  240 , at least one sealing device  299 , at least one inner deflection device sleeve  270 , at least one flow regulator  610 , a flow regulator  280 , at least one outer deflection device sleeve  250 , and at least one deflection device mounting platform  260 . 
     In certain example embodiments, the body  320  of the rotary bit pushing device  220  includes at least one wall (e.g., wall  221 , wall  222 , wall  223 ). At least one of the walls (in this case, wall  221 ) can include one or more apertures  263  that traverse the wall. Also, the walls of the body  320  can have one or more inner surfaces (in this case, inner surface  227  and inner surface  228 ) that form a cavity  229  that traverses the length of the body  320 . Through the cavity  229  can flow drilling fluid  178 . The body  320  can have a proximal end (at the left side of  FIGS.  3 A- 3 C ) and a distal end (at the right side of  FIGS.  3 A- 3 C ). The length of the body  320  is defined by the proximal end and the distal end. 
     The proximal end and the distal end of the body  320  can include one or more coupling features (e.g., mating threads) that allow the body  320  to couple to one or more components (e.g., near bit stabilizer  224 , bit shaft  235 ) of the bottom hole assembly  170 . The one or more apertures  263  in the body  320  can have characteristics (e.g., shape, size) sufficient to receive one or more other components of the rotary bit pushing device  220 . For example, as shown in  FIGS.  3 A- 3 C , the apertures  263  in the body  320  can receive and be coupled to one or more outer deflection device sleeves  250  (discussed below). 
     In certain optional example embodiments, as shown in  FIGS.  3 A- 3 C , the body  320  of the rotary bit pushing device  220  can include one or more deflection device mounting platforms  260 . In such a case, a deflection device mounting platform  260  can be integrated with (e.g., form a single piece with) the body  320 . Alternatively, a deflection device mounting platform  260  can be a separate piece that is mechanically coupled to the body  320 . A deflection device mounting platform  260  can protrude outward from the body  320  in a radial direction relative to an axis defined along the length of the body  320 . 
     A deflection device mounting platform  260  (or another portion of the body  320 ) can include one or more coupling features  251  (in this case, apertures that traverse the deflection device mounting platform  260  and/or the body  320 ) that are used to couple the body  320 , directly or indirectly, to one or more other components of the rotary bit pushing device  220 . For example, as shown in  FIGS.  3 A- 3 C , an outer deflection device sleeve  250 , disposed within an aperture  263  of the body  320 , can be indirectly coupled to a deflection device mounting platform  260  of the body  320  using one or more coupling devices  256  (in this case, bolts and washers) that traverse the coupling features  251  in the deflection device mounting platform  260  and corresponding coupling features  252  (in this case, apertures) that traverse at least a portion of the outer deflection device sleeve  250 . 
     In certain example embodiments, the body  320  can include at least one channel  282  disposed within the body  320 . In other words, the channel  282  can be disposed between an inner surface (e.g., inner surface  227 ) and an outer surface of one or more walls (in this case, wall  223 , wall  222 , and wall  221 ) of the body  320 . Each channel  282  can have characteristics (e.g., cross-sectional shape, cross-sectional size, length, curvature, bends, straight segments) sufficient to allow drilling fluid  178  to flow therethrough. Each channel  282  can be disposed between the flow regulator  280  (described below and disposed at the proximal end of the body  320 ) and one or more nozzles  265 . 
     Each of the one or more nozzles  265  of the body  320  can be disposed with an aperture  263  in a wall of the body  320  and is coupled to some portion (e.g., the distal end, toward the distal end) of a channel  282 . In certain example embodiments, each nozzle  265  is configured to direct drilling fluid  178  to a point where a deflection device  240  can be moved from a normal position to an extended position. In this case, a nozzle  265  directs drilling fluid  178  into a cavity  219  of a deflection device  240 . As such, a nozzle  265  can be disposed proximate to an underside of (within the cavity formed by) a deflection device  240 . 
     A nozzle  265  can have any of a number of features and/or configurations. An example of a nozzle  265  is shown in  FIGS.  3 B and  3 C . In this case, a nozzle  265  has a body  267  with a channel  268 , formed by an inner surface  269 , disposed therein. The outer surface of the body  267  of a nozzle  265  can have one or more coupling features  219  (in this case, mating threads) disposed thereon to allow the body  267  of the nozzle  265  to couple to one or more other components (e.g., an inner deflection device sleeve  270 , as in this case) of the rotary bit pushing device  220 . One or more sealing devices  266  can be disposed around the body  267  of a nozzle  265  to help prevent drilling fluid  178  from flowing in places that could adversely affect the operation of the rotary bit pushing device  220 . Each nozzle  265  can remain in an affixed position relative to the body  320  of the rotary bit pushing device  220 . 
     In certain example embodiments, an inner deflection device sleeve  270  is coupled to a nozzle  265 . An inner deflection device sleeve  270  can have any of a number of features and/or configurations. An example of an inner deflection device sleeve  270  is shown in FIGS.  3 B,  3 C,  5 A, and  5 B. In this case, an inner deflection device sleeve  270  has at least one wall  271  with an inner surface  275  that forms a cavity  218  that extends along the length of the inner deflection device sleeve  270 . There can be one or more coupling features  276  disposed along at least a portion of the inner surface  275  of the inner deflection device sleeve  270 . In this case, the coupling features  276  are mating threads that complement the coupling features  219  of a nozzle  265 . 
     In certain example embodiments, at least a portion of the outer surface  271  of the wall  274  of the inner deflection device sleeve  270  can be smooth and featureless. The cross-sectional size and shape (when viewed from above) of the outer surface  271  of the wall  274  of the inner deflection device sleeve  270  can be substantially the same as, or slightly larger than, the cross-sectional size and shape (when viewed from above) of the inner surface  297  of the sealing device  299  (described below). In addition, the cross-sectional size and shape (when viewed from above) of the outer surface  271  of the wall  274  of the inner deflection device sleeve  270  can be substantially the same as, or slightly smaller than, the cross-sectional size and shape (when viewed from above) of the inner surface  237  of the wall  244  of a deflection device  240 . 
     As a result, an inner deflection device sleeve  270  can be configured to remain affixed to nozzle  265  while allowing a deflection device  240  to move up and down relative to (along the length of) the inner deflection device sleeve  270 . When the deflection device  240  moves up and down relative to the inner deflection device sleeve  270 , the sealing device  299 , which is lodged within a channel of the deflection device  240  (as described below), slides along the smooth and featureless outer surface  271  of the wall  274  of the inner deflection device sleeve  270 . When this occurs, a liquid-tight seal can be maintained between the sealing device  299  and the inner deflection device sleeve  270 . 
     An inner deflection device sleeve  270  can also include a number of relief features  273  disposed along the top surface  272  of the wall  274  of the inner deflection device sleeve  270 . The relief features  273  can have any of a number of forms and/or characteristics. For example, in this case, the relief features  273  are apertures of varying outer perimeters that traverse a portion of the wall  274  of the inner deflection device sleeve  270 . In some cases, an inner deflection device sleeve  270  can be considered part of a deflection device  240 . 
     In certain optional example embodiments, one or more outer deflection device sleeves  250  are used to retain one or more deflection devices  240  and control the movement (e.g., path of travel, limitation of movement) of each deflection device  240 . If an outer deflection device sleeve  250  is not present, then the features described below with respect to the outer deflection device sleeve  250  can be incorporated into the body  320  of the rotary bit pushing device  220 . The outer deflection device sleeve  250  can have one or more apertures  253 , defined by an inner surface  254 , that traverse the entire height of the outer deflection device sleeve  250 . In such a case, the characteristics (e.g., cross-sectional shape, cross-sectional size, height, coupling features  259 ) of the aperture  253  and the inner surface  254  that defines the aperture  253  can be substantially the same as (or slightly larger than) the corresponding characteristics of the deflection device  240  disposed within the aperture  253 . 
     The coupling features  259  disposed in the inner surface  254  of the outer deflection device sleeve  250  can be configured to complement the coupling features  243  (described below) disposed on a deflection device  240 . The coupling features  243  can have any of a number of forms and/or characteristics. For example, in this case, the coupling features  243  are recesses that extend along a portion of the height of the outer deflection device sleeve  250 . The purpose of the coupling features  243  is to allow a deflection device  240  to slide up and down (radially in and out relative to an axis along the length of the rotary bit pushing device  220 ) in a limited range of motion. The coupling features  243  also prevent the deflection device  240  from rotating or otherwise moving in any direction other than straight up and straight down within the aperture  253 . 
     In certain example embodiments, an outer deflection device sleeve  250  can also include one or more channels  283  disposed toward the bottom of the outer deflection device sleeve  250  and adjacent to where a recessed segment  296  (described below) at the bottom end  295  of one or more deflection devices  240  is positioned when the deflection device  240  is disposed within the aperture  263  in the wall  221  of the body  320 . Each channel  283  can be used to facilitate the flow of drilling fluid  178  from the flow regulator  610  to and/or between one or more deflection devices  240 . Such drilling fluid  178  flowing through the flow regulator  610 , the recessed segments  296 , and the channels  283  can be used to ensure that cuttings and other debris from the wellbore  130  to not enter into and contaminate one or more portions of the rotary bit pushing device  220 . 
     When there are one or more outer deflection device sleeves  250 , an outer deflection device sleeve  250  is disposed in an aperture  263  in the wall  221  of the body  320 . In such a case, the top surface  258  of the outer deflection device sleeve  250  can be substantially planar with the top surface of a deflection device mounting platform  260  (or, if there is no deflection device mounting platform  260 , with the top surface of a wall (e.g., wall  221 ) of the body  320 ). 
     The features of the inner surface of a deflection device mounting platform  260  can complement corresponding features of the outer surface of an outer deflection device sleeve  250 . For example, as shown in  FIGS.  3 A and  3 B , adjacent to where an aperture  253  traverses an outer deflection device sleeve  250 , the outer side surface  255  can protrude beyond the outer side surface  257  of the outer deflection device sleeve  250  that is not adjacent to an aperture  253 . In such a case, the inner surface forming the aperture  263  in a deflection device mounting platform  260  can include a recessed portion  261  complementary to each protruding outer side surface  255  of the outer deflection device sleeve  250 , as well as a non-recessed portion  262  complementary to each outer side surface  257  of the outer deflection device sleeve  250 . 
     In this way, when an outer deflection device sleeve  250  is disposed within (e.g., coupled to) a deflection device mounting platform  260 , there can be substantially no gaps therebetween. In certain example embodiments, a deflection device mounting platform  260  and/or an outer deflection device sleeve  250  can include a channel (not shown) inside of which one or more sealing devices (also not shown) can be disposed to help ensure a liquid-tight seal between the outer deflection device sleeve  250  and the deflection device mounting platform  260 . 
     In certain example embodiments, a deflection device  240  is a movable object that is extended away from the rotary bit pushing device  220  at certain times in order to contact a wall of the wellbore  130  and thereby push the rotary drill bit  232  during a field operation. The deflection device  240  can include one or more features and/or characteristics. For example, as shown in  FIGS.  3 A- 4 D , the deflection device  240  can include a curved (e.g., convex) top surface  241 . In some cases, the top surface  241  has no openings or apertures. There can be a transition portion  292  (e.g., rounded, squared) between the top surface  241  and the outer surface  246  of the deflection device. Similarly, proximate to the coupling features  243  (discussed below), there can be a transition portion  291  between the top surface  241  and the coupling features  243 . 
     Alternatively, as shown in  FIGS.  4 C and  4 D , the top surface  241  can include at least one drainage channel  278  that traverses the top surface  241 . In such a case, the drainage channel  278  can include one or more of a number of features and/or components. For example, the drainage channel  278  can include a proximal aperture  238  adjacent to the cavity  219 , an outlet channel  239  that abuts against the proximal aperture  238  and has a smaller cross-sectional size compared to that of the outlet channel  239 , and flow control device  279  disposed between the outlet channel  239  and the proximal aperture  238 . The drainage channel  278  can be configured to let drilling fluid  178  disposed in the cavity  219  to flow outside the cavity  219  through the drainage channel  278  without allowing drilling mud  180  in the wellbore to flow through the drainage channel  278  into the cavity  219 . In addition to the top surface  241 , a deflection device  240  can also include a side wall that has an inner surface  237  and an outer surface  246 . 
     Disposed on at least one portion of the outer surface  246  can be a coupling feature  243 . As discussed above, the coupling feature  243  of a deflection device  240  can be configured to complement a coupling feature  259  of an outer deflection device sleeve  250 . In this case, the coupling feature  243  is a protruding section  244  that runs along the height of the deflection device  240 . On either side of the protruding section  244  can be a recess  245  that also runs along the height of the deflection device  240 . As discussed above, this configuration of the coupling feature  243  allows the deflection device  240  to slide up and down (radially in and out relative to an axis along the length of the rotary bit pushing device  220 ) relative to the outer deflection device sleeve  250 . The coupling features  243  also prevent the deflection device  240  from rotating or otherwise moving in any direction other than straight up and straight down within the aperture  253  of the outer deflection device sleeve  250 . 
     A deflection device  240  can have one coupling feature  243  or multiple coupling features  243 . In certain example embodiments, as shown in  FIG.  4 B , the coupling feature  243  can include a stop  242 . In such a case, the stop  242  can limit the amount of up and down travel of the deflection device  240  within the coupling feature  259  of the outer deflection device sleeve  250 . The stop  242  can include a base portion  247  that extends laterally away from the protruding section  244  of the coupling feature  243 . The stop  242  can also include an extension  242  disposed at the distal end of the base portion  247 . The stop  242  can form a single piece with the protruding section  244 . Alternatively, as shown in  FIGS.  4 A- 4 D , the stop  242  can be a separate piece that couples to a coupling feature  249  (e.g., an aperture) disposed on the protruding section  244 . 
     The inner surface  237  of the deflection device  240  can form a cavity  219  that is bounded on the sides by the inner surface  237  and is bounded (or, if the drainage channel  278  is present, substantially bounded) at the top by the top surface  241 . In certain example embodiments, disposed along some or all of the perimeter of the inner surface  237 , is disposed a coupling feature  293  (in this case, a channel). The coupling feature  293  can be used to receive the sealing device  299 . In other words, the characteristics (e.g., shape, size) of the coupling feature  293  can be designed to complement the corresponding characteristics of the sealing device  299 . For example, the outer surface  298  of the sealing device  299  can abut against the inner surface of the coupling feature  293 . 
     In certain example embodiments, the inner surface  297  of the sealing device  299  can extend into the cavity  219  beyond the  237  of the deflection device  240 . In such a case, the inner surface  297  of the sealing device  299  can abut against a create a liquid-tight seal with the outer surface  271  of the wall  274  of the inner deflection device sleeve  270  while the deflection device  240  freely moves up and down (subject to coupling feature  243  of the deflection device  240  movably coupled to coupling feature  259  of the outer deflection device sleeve  250 ) relative to the inner deflection device sleeve  270 . In certain example embodiments, the sealing device  299  can divide a deflection device  240  and/or a corresponding inner deflection device sleeve  270  into an upper portion and a lower portion, where the lower portion is below the sealing device  299  adjacent to the cavity  219  and the upper portion is above the sealing device  299 . 
     The bottom end  295  of the deflection device  240  can include one or more features that receive and distribute drilling fluid  178  received from a flow regulator  610  (described below). For example, as shown in  FIGS.  4 C and  4 D , the bottom end  295  of the deflection device  240  can include a recessed channel  294  bounded on the inner surface and the outer surface by the bottom end  295 . In other words, the recessed channel  294  does not traverse the entire width (thickness) of the deflection device  240 . The recessed channel  294  meets at least one recessed segment  296 , which traverses the entire width of the deflection device  240 . As a result, the recessed channel  294  and the recessed segments  296  form a continuous recessed volume of space around the entire perimeter of the bottom end  295  of the deflection device  240 . 
     A recessed segment  296  of the deflection device  240  can be located proximate to a flow regulator  610  when the deflection device  240  is in a normal position. (When the deflection device  240  is in an extended position, the recessed segment  296  of the deflection device  240  can be located slightly further away from the flow regulator  610 .) As a result, when drilling fluid  178  flows through the flow regulator  610 , the drilling fluid  178  flows into the recessed segment  296 . Subsequently, the drilling fluid  178  can flow from the recessed segment  296  to the recessed channel  294 . The drilling fluid  178  can also flow from the recessed segment  296  to the cavity  219  of the deflection device  240 . 
     The drilling fluid  178  in the recessed channel  294  can flow into another recessed segment  296  of the deflection device  240 , and from there the drilling fluid  178  can flow into the channel  283  of the deflection device holder  283 . Since the channel  283  provides a flow path between two or more adjacent deflection devices  240 , the drilling fluid  178  can flow to a recessed segment  296  of one or more other deflection devices  240 . 
     In certain example embodiments, the flow regulator  610  is a component of the rotary bit pushing device  220  that controls an amount of drilling fluid  178  that flows from the cavity  229  of the body  320  into a recessed segment  296  of a deflection device  240 . This flow of the drilling fluid  178  through the flow regulator  610  can provide a substantially constant flow of drilling fluid  178  out of the deflection devices  240  (e.g., through a drainage channel  278  of a deflection device  240 ), which prevents cuttings and other undesired elements in the wellbore  130  from entering the rotary bit pushing device  220  or portions thereof. 
     A detail of an example flow regulator  610  is shown in  FIG.  6   . The flow regulator  610  can have any of a number of features and/or configurations. For example, as shown in  FIG.  6   , a flow regulator  610  can have a T-shaped body  612  with one or more sealing devices (e.g., sealing device  613 , sealing device  614 ) disposed around an outer perimeter of the body  612 . The body  612  can have a channel  611  disposed therein that traverse the height of the body. At the top of the body  612 , adjacent to a recessed segment  296 , can be one or more apertures  616  through which the drilling fluid  178  is released. 
     The channel  611  of the flow regulator  610  can be open at all times. Alternatively, the channel  611  of the flow regulator  610  can be open intermittently, as to coincide with times during the rotation of the rotary bit pushing device  220  within the wellbore  130  when the adjacent deflection devices  240  are no longer in an extended position. As another alternative, the flow of drilling fluid  178  through the channel  611  can always exist, but the amount of drilling fluid  178  flowing through the channel  611  at a given instant can vary. If the flow of drilling fluid  178  through the flow regulator  610  varies, a controller (e.g., controller  103  can control the flow of drilling fluid  178  through the flow regulator  610 . 
     In certain example embodiments, the flow regulator  280  is a component of the rotary bit pushing device  220  that controls an amount of drilling fluid  178  that is diverted from the cavity  229  of the body  320  and directed to flow into a channel  282  of the body  320  and subsequently into a cavity  219  of one or more deflection devices  240 . This flow of the drilling fluid  178  through the flow regulator  280  can provide an on-demand, periodic flow of drilling fluid  178  into a cavity  219  of one or more deflection devices  240  to force the deflection devices  240  to move from a normal position to an extended position. 
     As discussed above, the bottom hole assembly  170 , including the rotary bit pushing device  220 , rotates around an axis formed by the length of the bottom hole assembly  170  when a field is being developed (e.g., when a wellbore  130  is being drilled to extend the wellbore  130 ). In order to push the rotary drill bit  232  in the desired direction to extend the wellbore  130 , the deflection devices  240  must be extended when the deflection devices  240  are located at a certain point or range of distances along the repeating 360° travel of the deflection devices  240  relative to the wellbore  130 . 
     For example, if a user wants to extend the wellbore  130  in a substantially downward direction, the deflection devices  240  need to be moved into the extended position when the deflection devices  240  are at or near the top of the wellbore  130 . In this way, the deflection devices  240 , when in the extended position, contact and push against the top of the wellbore  130 , which applies a downward force to the remainder of the bottom hole assembly  170 , at the end of which is disposed the rotary drill bit  232 . 
     A rotary bit pushing device  220  can have a single line or column of deflection devices  240 , where each line or column of deflection devices can have one or multiple deflection devices  240 . Alternatively, a rotary bit pushing device  220  can have multiple lines or columns of deflection devices  240 , where each line or column of deflection devices can have one or multiple deflection devices  240 . For example, as shown in  FIGS.  3 A- 3 C , the rotary bit pushing device  220  has three columns of deflection devices  240 , and each column has two deflection devices  240 . 
     When the rotary bit pushing device  220  has multiple columns of deflection devices  240 , the deflection devices  240  in each column must be controlled independently of the deflection devices  240  in the other columns. Without this independent control of the columns of deflection devices  240 , the rotary bit pushing device  220  would push the rotary drill bit  232  in an undesired direction. By contrast, multiple deflection devices  240  within a column can be controlled jointly or independently. If controlled independently, a flow regulator of some type can be incorporated into one or more of the nozzles  265 . 
     Returning to the discussion of the flow regulator  280 , as detailed in  FIG.  7   , the flow regulator  280  can have any of a number of features and/or configurations. For example, as shown in  FIGS.  3 C and  7   , a flow regulator  280  can have multiple inlet ports  285  disposed on face  286  of the flow regulator  280 , where each inlet port  285  feeds a separate inlet channel  281 , which ties into a channel  282  disposed within the body  320 . The inlet ports  185  and inlet channels  281  can help make up a port assembly  386  of the flow regulator  280 . The inlet ports  285  of the flow regulator  280  can be part of the same flow regulator  280 . Alternatively, each inlet port  285  can be part of an independent flow regulator  280 . 
     Regardless of how many inlet ports  285  the flow regulator  280  has, each inlet port  285  can be independently opened and closed relative to the other inlet ports  285 . A local controller  203 , embedded within the flow regulator  280 , can be used to open and close each of the inlet ports  285 . The controller  203  can communicate with the data acquisition system  101  (e.g., the controller  103 ), using wired and/or wireless (e.g., signals transmitted through the drilling fluid  178 ) technology. The controller  203  can open and close the various inlet channels  285  in one or more of a number of ways. For example, an inlet port  285  can be closed by closing a valve (not shown) disposed within the inlet channel  281  of that inlet port  285 . As another example, the controller  203  can rotate the port assembly  386  at different points along the rotational travel of the rotary bit pushing device  220 . In such a case, rotating the port assembly  386  can open or close an inlet port  285 , depending on the location of the inlet port  285  relative to an inlet channel  281 . 
     The flow regulator  280  can include one or more sealing devices (not shown) disposed around an outer perimeter of the body  287  and/or body  288 . The flow regulator  280  can be integrated with, or a separate component that is mechanically coupled to, the rotary bit pushing device  220 . In certain example embodiments, adjacent to the flow regulator  280  can be disposed one or more flow-through channels  284  that traverse a wall (e.g., wall  222 ) of the body  320 . The flow-through channel  284  opens into the cavity  229  that traverses the length of the body  320 . This flow-through channel  284  allows a portion of the drilling fluid  178 , separate from the drilling fluid that flows through the flow regulator  280 , to flow to the flow regulator  610 . The flow-through channel  284  can have a valve (not shown) or similar flow regulator disposed therein. Alternatively, the flow-through channel  284  can be unobstructed at all times, allowing a constant flow of drilling fluid  178  to flow therethrough. 
       FIG.  8    shows a flowchart of a method  800  for pushing a rotary drill bit in accordance with one or more example embodiments. While the various steps in the flowchart presented herein are described sequentially, one of ordinary skill will appreciate that some or all of the steps may be executed in different orders, may be combined or omitted, and some or all of the steps may be executed in parallel. Further, in one or more of the example embodiments, one or more of the steps described below may be omitted, repeated, and/or performed in a different order. In addition, a person of ordinary skill in the art will appreciate that additional steps may be included in performing the methods described herein. Accordingly, the specific arrangement of steps shown should not be construed as limiting the scope. Further, in one or more example embodiments, a particular computing device, as described, for example, in  FIG.  9    below, is used to perform one or more of the method steps described herein. 
     Referring now to  FIGS.  1 - 8   , the example method  800  begins at the START step and continues to step  802 , where a target direction in a formation to push the rotary drill bit  232  while drilling a wellbore  130  is received. The target direction is a direction in which a rotary drill bit  232  is pushed within the wellbore  130  while performing a field operation. For example, the field operation can be drilling a wellbore  130  in a subterranean formation  105 . In one or more example embodiments, the target direction is a particular radial direction away from the current direction of the wellbore  130 . For example, the target direction can be up to a 10° axial deviation, which is the amount of deviation from the directional axis of the bottom hole assembly  170 . 
     The target direction can be received by a controller (e.g., controller  103 , controller  203 ), which can be located, for example, above the surface  104  and/or within the flow regulator  280 . The target direction can be sent by a data acquisition system  101  (or portion thereof), which can be located at the surface  104  or at any other location. The target direction can be received by the flow regulator  280  (e.g., the controller  203 ) using wired and/or wireless technology. For example, pulses can be sent through the drilling fluid in the wellbore  130 , received by the flow regulator  280 , and translated into readable instructions relative to pushing the drill bit  232 . 
     In step  804 , a first inlet port  285  of a first flow regulator  280  is opened. The first inlet port  285  can be opened at a first rotational position of a rotary bit pushing device  220  disposed proximate to the rotary drill bit  232  within the wellbore  130 . The first inlet port  285 , when in an open position, allows a first quantity of drilling fluid  178  to move a first deflection device  240  (or column of first deflection devices  240 ) of the rotary bit pushing device  220  from a normal position to an extended position. The first deflection device  240 , when in the extended position, contacts the formation bounding the wellbore  130 . The first deflection device  240  is among a number of deflection devices  240 . 
     The first rotational position coincides with the target direction at that particular point in time during the field operation. The first rotational position can be a point or an area of rotation relative to the target direction. The first deflection device  240  can be put in the extended position (enabled) by the fluid pressure of the drilling fluid  178  when the drilling fluid  178  fills the cavity  219 . For example, if the first deflection device  240  is a piston, pressurizing the cavity  219  of the first deflection device  240  using the drilling fluid  178  enables the first deflection device  240 . In certain example embodiments, the first inlet port  285  allows the drilling fluid  178  to flow therethrough based on instructions received from a data acquisition system  101  (or portion thereof, such as a controller  103 ). 
     In certain example embodiments, the first inlet port  285  of the first flow regulator  280  is opened using the controller  203  of the first flow regulator  280 . Specifically, the controller  203  can rotate the port assembly  386  of the first flow regulator  280  to a certain position to open the first inlet port  285 . As another example, the controller  203  can open a valve internal to the port assembly  386 , where the valve is in the inlet channel  281  fed by the first inlet port  285 . At least a portion of the first quantity of drilling fluid  178  flows through the first deflection device  240  (e.g., through the drainage channel  278 ) into the wellbore when the first inlet port is in the closed position. 
     In step  806 , the first inlet port  285  is closed. The first inlet port  285  can be closed after the first rotational position of the rotary bit pushing device  240 . The first inlet port  285  can be closed by the controller  103  and/or the controller  203  in the same way that the first inlet port  285  was opened in step  604 . The first inlet port  285 , when in a closed position, stops the first quantity of drilling fluid  178  from flowing to the first deflection device  240  and allows the first deflection device  240  to return to the normal position. As described herein, allowing a deflection device  240  to return to the normal position can also be called disengaging the deflection device  240 . By stopping the flow of drilling fluid  178  to the cavity  219  of the deflection device  240 , the force keeping the deflection device  240  in the extended position is removed. In certain example embodiments, the first inlet port  285  is closed based on instructions received from a data acquisition system  101  or portion thereof. 
     In step  808 , a second quantity of drilling fluid  178  is sent to a second flow regulator  610  of the rotary bit pushing device  220 . The second quantity of drilling fluid  178  can flow through the second flow regulator  610  to the first deflection device  240  when the first inlet port is in the closed position. In addition, the second quantity of drilling fluid  178  can flow through the second flow regulator  610  to the first deflection device  240  when the first inlet port is in the open position. In such a case, the second quantity of drilling fluid  178  can flow through the second flow regulator  610  to the first deflection device  240  at all times, regardless of the position of first inlet port. In this way, drilling fluid  178  will always be flowing through the drainage channel  278  of the deflection device  240 , thereby keeping any debris from entering the deflection device  240  and jeopardizing the mechanical integrity of the rotary bit pushing device  220 . The second quantity of drilling fluid  178  can flow into the cavity  229  through the flow-through channel  284 . 
     As the rotary bit pushing device  220  rotates with the rest of the bottom hole assembly  170  during a field operation, a second deflection device  240  (or column of second deflection devices  240 ) can be enabled at a second rotational position when a second inlet port  285  is opened. The second deflection device  240  can be adjacent to the first deflection device  240 , on the opposite side of the body  320  from the first deflection device  440 , or at some other position relative to the first deflection device  240 . Further, the second inlet port  285  can be adjacent to the first inlet port  285 , on the opposite side of the flow regulator  280  from the first inlet port  285 , or at some other position relative to the first inlet port  285 . Similarly, the second rotational position can be adjacent to the first rotational position, on the opposite side of the bottom hole assembly  170  from the first rotational position, or at some other position relative to the first rotational position. In certain example embodiments, the second deflection device can be enabled at substantially the same time as step  606 . 
     The second rotational position coincides with the target direction at that particular point in time during the field operation. The second rotational position can be a point or an area of rotation relative to the target direction. The second inlet port  285  can be opened by the controller  103  and/or the controller  203 . In certain example embodiments, the controller  203  opens (and subsequently closes) the second inlet port  285  based on instructions received from a data acquisition system  101 . The second deflection device  240  can be enabled in the same or a different manner than the manner in which the first deflection device  240  is enabled. 
     After the second inlet port  285  is opened, the second inlet port  285  is closed after the second rotational position. Closing the second inlet port  285  disables the second deflection device  240 . The second inlet port  285  can be closed using the controller  103  and/or the controller  203 . The controller  203  can open the second inlet port  285  actively or passively. In certain example embodiments, the controller  203  closes the second inlet port  285  based on instructions received from a data acquisition system  101 . 
     The steps described above can cover one full revolution of the bottom hole assembly  170  if there are only two deflection devices  240  and/or inlet ports  285 . If there are more than two deflection devices  240  and/or inlet ports  285 , then each of the additional deflection devices  240  and/or inlet port  285  is similarly enabled/disabled and/or opened/closed when the respective additional deflection device  240  and/or inlet port  285  enters and leaves a rotational position that corresponds to the target position. In certain example embodiments, the bottom hole assembly can rotate up to 200 rpm. If the controller  203  continues to receive instructions from the data acquisition system  101 , then steps  804  through  808  of the method  800  are repeated for additional revolutions of the bottom hole assembly  170  until the controller  203  stops receiving such instructions and/or receives different instructions. The example process then proceeds to the END step. 
       FIG.  9    illustrates one example of a computing device  918  used to implement one or more of the various techniques described herein, and which may be representative, in whole or in part, of the elements described herein. The computing device  918  is only one example of a computing device and is not intended to suggest any limitation as to scope of use or functionality of the computing device and/or its possible architectures. Neither should the computing device  918  be interpreted as having any dependency or requirement relating to any one or combination of components illustrated in the example computing device  918 . 
     Referring to  FIGS.  1 - 9   , the computing device  918  includes one or more processors or processing units  914 , one or more memory/storage components  915 , one or more input/output (I/O) devices  916 , and a bus  917  that allows the various components and devices to communicate with one another. Bus  917  represents one or more of any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. Bus  917  can include wired and/or wireless buses. 
     Memory/storage component  915  represents one or more computer storage media. Memory/storage component  915  may include volatile media (such as random access memory (RAM)) and/or nonvolatile media (such as read only memory (ROM), flash memory, optical disks, magnetic disks, and so forth). Memory/storage component  915  can include fixed media (e.g., RAM, ROM, a fixed hard drive, etc.) as well as removable media (e.g., a Flash memory drive, a removable hard drive, an optical disk, and so forth). 
     One or more I/O devices  916  allow a customer, utility, or other user to enter commands and information to computing device  918 , and also allow information to be presented to the customer, utility, or other user and/or other components or devices. Examples of input devices include, but are not limited to, a keyboard, a cursor control device (e.g., a mouse), a microphone, and a scanner. Examples of output devices include, but are not limited to, a display device (e.g., a monitor or projector), speakers, a printer, and a network card. 
     Various techniques may be described herein in the general context of software or program modules. Generally, software includes routines, programs, objects, components, data structures, and so forth that perform particular tasks or implement particular abstract data types. An implementation of these modules and techniques may be stored on or transmitted across some form of computer readable media. Computer readable media may be any available non-transitory medium or non-transitory media that can be accessed by a computing device. By way of example, and not limitation, computer readable media may comprise “computer storage media”. 
     “Computer storage media” and “computer readable medium” include volatile and non-volatile, removable and non-removable media implemented in any method or technology for storage of information such as computer readable instructions, data structures, program modules, or other data. Computer storage media include, but are not limited to, computer recordable media such as RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which can be used to store the desired information and which can be accessed by a computer. 
     The computing device  918  may be connected to a network (not shown) (e.g., a local area network (LAN), a wide area network (WAN) such as the Internet, or any other similar type of network) via a network interface connection (not shown). Those skilled in the art will appreciate that many different types of computer systems exist (e.g., desktop computer, a laptop computer, a personal media device, a mobile device, such as a cell phone or personal digital assistant, or any other computing system capable of executing computer readable instructions), and the aforementioned input and output means may take other forms, now known or later developed. Generally speaking, the computing system  918  includes at least the minimal processing, input, and/or output means necessary to practice one or more embodiments. 
     Further, those skilled in the art will appreciate that one or more elements of the aforementioned computing device  918  may be located at a remote location and connected to the other elements over a network. Further, one or more embodiments may be implemented on a distributed system having a plurality of nodes, where each portion of the implementation (e.g., controller  103 , controller  203 ) may be located on a different node within the distributed system. In one or more embodiments, the node corresponds to a computer system. Alternatively, the node may correspond to a processor with associated physical memory. The node may alternatively correspond to a processor with shared memory and/or resources. 
     The example embodiments discussed herein provide for pushing a rotary drill bit in a particular direction during a field operation. Specifically, the example embodiments enable and disable various portions of a rotary bit pushing device, positioned between the proximal end of a control shaft and a universal joint. In such a case, the rotary bit pushing device applies a force to the control shaft that remains substantially constant in magnitude and direction relative to the wellbore being drilled, despite the substantially constant rotation of the bottom hole assembly. 
     When the force is applied to the proximal end of the control shaft, the universal joint causes a substantially equal and opposing force to be applied by the distal end of the control shaft to the bit shaft. This force applied to the bit shaft pushes the bit in the target direction. 
     Although the invention is described with reference to example embodiments, it should be appreciated by those skilled in the art that various modifications are well within the scope and spirit of this disclosure. Those skilled in the art will appreciate that the present invention is not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the example embodiments, equivalents of the elements shown therein will suggest themselves to those skilled in the art, and ways of constructing other embodiments of the present invention will suggest themselves to practitioners of the art. Therefore, the scope of the present invention is not limited herein.