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CROSS-REFERENCE TO RELATED APPLICATIONS  
       [0001]     None  
       BACKGROUND OF THE INVENTION  
       [0002]     The present invention generally relates to apparatuses and methods to perform rotary steerable directional drilling operations. More particularly, the present invention relates to downhole actuators to position a drill bit assembly in a desired trajectory by a rotary steerable assembly. More particularly still, the present invention relates to a bi-directional actuator to be used in a rotary steerable system to accommodate more precise positioning of a drill bit assembly.  
         [0003]     Boreholes are frequently drilled into the Earth&#39;s formation to recover deposits of hydrocarbons and other desirable materials trapped beneath the Earth&#39;s crust. Traditionally, a well is drilled using a drill bit attached to the lower end of what is known in the art as a drillstring. The drillstring is a long string of sections of drill pipe that are connected together end-to-end through rotary threaded pipe connections. The drillstring is rotated by a drilling rig at the surface thereby rotating the attached drill bit. The weight of the drillstring typically provides all the force necessary to drive the drill bit deeper, but weight may be added (or taken up) at the surface, if necessary. Drilling fluid, or mud, is typically pumped down through the bore of the drillstring and exits through ports at the drill bit. The drilling fluid acts both lubricate and cool the drill bit as well as to carry cuttings back to the surface. Typically, drilling mud is pumped from the surface to the drill bit through the bore of the drillstring, and is allowed to return with the cuttings through the annulus formed between the drillstring and the drilled borehole wall. At the surface, the drilling fluid is filtered to remove the cuttings and is often used recycled.  
         [0004]     In typical drilling operations, a drilling rig and rotary table are used to rotate a drillstring to drill a borehole through the subterranean formations that may contain oil and gas deposits. At downhole end of the drillstring is a collection of drilling tools and measurement devices commonly known as a Bottom Hole Assembly (BHA). Typically, the BHA includes the drill bit, any directional or formation measurement tools, deviated drilling mechanisms, mud motors, and weight collars that are used in the drilling operation. A measurement while drilling (MWD) or logging while drilling (LWD) collar is often positioned just above the drill bit to take measurements relating to the properties of the formation as borehole is being drilled. Measurements recorded from MWD and LWD systems may be transmitted to the surface in real-time using a variety of methods known to those skilled in the art. Once received, these measurements will enable those at the surface to make decisions concerning the drilling operation. For the purposes of this application, the term MWD is used to refer either to an MWD (sometimes called a directional) system or an LWD (sometimes called a formation evaluation) system. Those having ordinary skill in the art will realize that there are differences between these two types of systems, but the differences are not germane to the embodiments of the invention.  
         [0005]     A popular form of drilling is called “directional drilling.” Directional drilling is the intentional deviation of the wellbore from the path it would naturally take. In other words, directional drilling is the steering of the drill string so that it travels in a desired direction. Directional drilling is advantageous offshore because it enables several wells to be drilled from a single platform. Directional drilling also enables horizontal drilling through a reservoir. Horizontal drilling enables a longer length of the wellbore to traverse the reservoir, which increases the production rate from the well. A directional drilling system may also be beneficial in situations where a vertical wellbore is desired. Often the drill bit will veer off of a planned drilling trajectory because of the unpredictable nature of the formations being penetrated or the varying forces that the drill bit experiences. When such a deviation occurs, a directional drilling system may be used to put the drill bit back on course.  
         [0006]     A traditional method of directional drilling uses a bottom hole assembly that includes a bent housing and a mud motor. The bent housing includes an upper section and a lower section that are formed on the same section of drill pipe, but are separated by a permanent bend in the pipe. Instead of rotating the drillstring from the surface, the drill bit in a bent housing drilling apparatus is pointed in the desired drilling direction, and the drill bit is rotated by a mud motor located in the BHA. A mud motor converts some of the energy of the mud flowing down through the drill pipe into a rotational motion that drives the drill bit. Thus, buy maintaining the bent housing at the same azimuth relative to the borehole, the drill bit will drill in a desired direction. When straight drilling is desired, the entire drill string, including the bent housing, is rotated from the surface. The drill bit angulates with the bent housing and drills a slightly overbore, but straight, borehole.  
         [0007]     A more modern approach to directional drilling involves the use of a rotary steerable system (RSS). In an RSS, the drill string is rotated from the surface and downhole devices force the drill bit to drill in the desired direction. Rotating the drill string is preferable because it greatly reduces the potential for getting the drillstring stuck in the borehole. Generally, there are two types of RSS, “point the bit” systems and “push the bit” systems. In a point system, the drill bit is pointed in the desired position of the borehole deviation in a similar manner to that of a bent housing system. In a push system, devices on the BHA push the drill bit laterally in the direction of the desired borehole deviation by pressing on the borehole wall.  
         [0008]     A point the bit system works in a similar manner to a bent housing because a point system typically includes a mechanism to provide a drill bit alignment that is different from the drill string axis. The primary differences are that a bent housing has a permanent bend at a fixed angle and a point the bit RSS typically has an adjustable bend angle that is controlled independent of the rotation from the surface. A point RSS typically has a drill collar and a drill bit shaft. The drill collar typically includes an internal orienting and control mechanism that counter rotates relative to the rotation of the drillstring. This internal mechanism controls the angular orientation of the drill bit shaft relative to the borehole. The angle between the drill bit shaft and the drill collar may be selectively controlled, but a typical angle is less than 2 degrees. The counter rotating mechanism rotates in the opposite direction of the drill string rotation. Typically, the counter rotation occurs at the same speed as the drill string rotation so that the counter-rotating section maintains the same angular position relative to the inside of the borehole. Because the counter rotating section does not rotate with respect to the borehole, it is often called “geo-stationary” by those skilled in the art.  
         [0009]     A push the bit RSS system typically uses either an internal or an external counter-rotation stabilizer. The counter rotation stabilizer remains at a fixed angle (geo-stationary) with respect to the borehole while the drillstring above is rotated. When borehole deviation is desired, an actuator presses a pad against the borehole wall in the direction opposite the desired trajectory. This operation results in a drill bit that is pushed in a desired direction. Typically, one or more actuator pads are located on a geo-stationary counter-rotating collar of the push the bit apparatus.  
         [0010]     Historically, push the bit and point the bit rotary steerable systems use their geostationary components either to aim, or to force the drill bit in a desired direction. When subterranean formations are either unknown or especially treacherous, forcing the bit is not always feasible. In those circumstances, aiming the bit may be preferable to forcing the bit in a wrong direction. Because uncertainty of the formation is always an issue in subterranean drilling, a system having the capabilities of both point and push the bit rotary steerable systems is desirable.  
       BRIEF SUMMARY OF THE INVENTION  
       [0011]     The deficiencies of the prior art are addressed by apparatuses and methods to manipulate a hybrid steering sleeve with actuator devices that are capable of positive and negative manipulation on a particular thrust axis. Preferably, the hybrid sleeve includes a plurality of bi-directional actuators to aim and force the hybrid sleeve into a preferred position and under a preferred force. The positions and forces of and exerted by the actuators are fully monitorable and controllable either by a downhole or a surface control device. The actuation of the bi-directional actuators is preferably controlled by drilling fluid pressures. A shielding mechanism is disclosed to protect any sealing components from the abrasive characteristics of the drilling fluids. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0012]     For a more detailed description of the preferred embodiments of the present invention, reference will not be made to the accompanying drawings, wherein:  
         [0013]      FIG. 1  is a schematic cross-sectional view of a bi-directional actuator assembly in the context of a directional drilling tool in accordance with a preferred embodiment of the present invention;  
         [0014]      FIG. 2  is a schematic cross-sectional view of the bi-directional actuator assembly of  FIG. 1  in positively biased state;  
         [0015]      FIG. 3  is a schematic cross-sectional view of the bi-directional actuator assembly of  FIG. 1  in a negatively biased state;  
         [0016]      FIG. 4  is a schematic cross-sectional view of the bi-directional actuator assembly of  FIG. 1  further including a protective membrane; and  
         [0017]      FIG. 5  is a schematic top-view drawing of a directional drilling tool utilizing two bi-directional actuator assemblies in accordance with the present invention. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0018]     Referring initially to  FIG. 1 , a schematic drawing for a bi-directional actuator assembly  100  in a downhole directional drilling tool  102  is shown. Directional drilling tool  102  uses actuator assembly  100  to displace hybrid sleeve  104  into a desired position on a single axis. Hybrid sleeve  104  preferably steers a drill bit (not shown) through a geostationary universal joint (not shown) that directs drill bit as hybrid sleeve  104  is displaced relative to directional drilling tool  102 . Preferably, two bi-directional actuator assemblies  100  would be employed by drilling tool  102  to form two orthogonal axis that define a plane normal to the axis of drilling tool  102 , but only a single bi-directional actuator  100  (single axis) is shown for the purposes of simplicity.  
         [0019]     Bi-directional actuator assembly  100  includes a piston  110  housed within a seal bore  112 . Piston  110  is allowed to reciprocate within seal bore  112  between stops  114 ,  116 . Piston  110  has a first thrust face  118  and a second thrust face  120  to transmit pressure forces thereupon into mechanical movement of piston  110 . A first arm  122  extends from first thrust face  118  and a second arm  124  extends from second thrust face  120 . Arms  122 ,  124  extend through ports  126 ,  128  of directional drilling tool  102  and engage load pads  130 ,  132  located upon an inside surface of hybrid sleeve  104 . The movement of piston  110  within seal bore  112  transmits force through arms  122 ,  124  to deflect hybrid sleeve  104  in a desired position along the axis of piston  110 .  
         [0020]     Bi-directional actuator assembly  100  operates under hydraulic pressure supplied by drilling fluids. Typically, drilling fluids are delivered to the bit through the central bore of drill pipe and various drilling tools. These fluids are then used, under pressure, to lubricate the drill bit, clean the drill bit, and carry the cuttings from the borehole back to the surface. At the surface, the cuttings and impurities are filtered out and the drilling fluid, or “mud,” is recycled for use again. Therefore, drilling fluids are transmitted to the bottom of a wellbore under high pressures through the bore of the drillstring and are returned to the surface at a relatively lower pressure in the annulus formed between the drillstring and the borehole wall. Because of this difference in delivery and return pressure, drilling fluids are often used to performed work in various drilling tools downhole.  
         [0021]     Returning to  FIG. 1 , high-pressure drilling fluids from the bore of the drillstring enter bi-directional actuator assembly  100  at a high-pressure manifold  134  through an inlet  136 . Because drilling fluids are typically slurry compositions, inlet  136  preferably includes some filtration mechanism to prevent solids in the drilling fluid from entering bi-directional actuator assembly  100 . Low-pressure fluids of the annulus between the drillstring and the borehole are in communication with the bi-directional actuator assembly  100  through a low-pressure manifold  138  and a port  140 . Manifolds  134 ,  238  are shown schematically as simple manifolds, but complex systems utilizing various ducts, valves, and controls may be employed. High-pressure manifold  134  communicates with piston  110  through ports A and B. Low-pressure manifold  138  communicates with piston  110  through ports C and D.  
         [0022]     A seal  142  mounted to piston  110  reciprocating within seal bore  112  creates a first pressure chamber  144  and a second pressure chamber  146  of bi-directional actuator assembly  100 . Seal  142  is shown schematically as a single o-ring seal but it should be known by one of ordinary skill in the art that any type of dynamic seal may be used. For example, double o-rings, wipers, and backup rings may be used to improve the reliability and integrity of seal  142 .  
         [0023]     First pressure chamber  144  acts on first face  118  of piston  110  and tends to urge piston  110  to the right when pressure therein is increased relative to second pressure chamber  146 . Second pressure chamber  146  acts on second face  120  of piston  110  and tends to urge piston  110  to the left when pressure therein is increased relative to first pressure chamber  144 . Seals  148 ,  150  maintain integrity of first and second pressure chambers  144 ,  146 , respectively, by preventing annulus fluid from communicating with chambers  44 , 146 . High-pressure port A and low-pressure port C are in communication with first pressure chamber  144 . High-pressure port B and low-pressure port D are in communication with second pressure chamber  146 . Valves  152 , shown schematically within ports A, B, C, and D, selectively allow or restrict the flow of drilling fluids from manifolds  134 ,  138  in or out of chambers  144 ,  146 . While valves  152  are shown schematically as integral to ports A, B, C, and D, it should be understood by one of ordinary skill in the art that various configurations and locations for valves  152  may be used. Particularly, valves A, B may be integral to manifold  134  and valves C, D may be integral to manifold  138 . Valves  152  are shown as is for illustrative purposes only and are not meant to be limiting on the scope of the claims.  
         [0024]     Optionally, a dynamic feedback system may be used with the bi-directional piston actuator assembly  100  of  FIG. 1 . Particularly, a series of pressure transducers  160  may be installed in communication with first and second chambers  144 ,  146  to monitor the relative pressure difference between chambers  144 ,  146 . Next, a N-S magnet device  162  may be mounted to the piston  110  such that a magnetic proximity (Hall Effect) detector  164  can determine the absolute position of piston  110  within seal bore. The information from the proximity detector  164  and the pressure transducers  160  can be either relayed to a processing unit (not shown) within directional drilling tool  102  or may be sent, via telemetry, to an operator at the surface. This information and the data created therefrom can be analyzed and used by to determine performance of bi-directional actuator assembly  100  and to determine what corrections, if any, are needed to steer the directional drilling tool  102  into its desired trajectory. Furthermore, using the date from transducers  160  and detector  164 , an operator can know the position of hybrid sleeve  104  with respect to drilling tool  102  at all times. Therefore, the controller or the operator can know the difference between the desired bid direction and the actual bit direction and be able to make adjustments thereof. While pressure transducers and magnetic sensors are shown to obtain pressure and position data for piston  110  and chambers  144 ,  146 , it should be understood by one of ordinary skill in the art that other mechanisms may be employed to obtain this data without departing from the spirit of the invention.  
         [0025]     Referring now to  FIG. 2 , piston  110  is shown displaced to the right, thus placing a “positive” bias upon hybrid sleeve  104 . To displace piston  110  in this manner, high-pressure drilling fluid from the bore of drillstring and directional drilling tool  102  enters high-pressure manifold  134  through filtration screen  136 . A controller (not shown) selectively opens port A and closes port B, thus allowing pressure within first chamber  144  to increase. The controller simultaneously opens port D and closes port C of the low-pressure manifold  138 , thereby allowing pressure within second chamber  146  to decrease. As pressure builds within first chamber  144 , that pressure acts upon face  118  and drives piston  110  toward the right side (positive displacement) until stop  116  is engaged. The movement of piston  110  to the right, likewise displaces second arm  124  to the right enabling the application of force to hybrid sleeve  104  through load pad  132 . Hybrid sleeve  104  displaces to the right under the force of piston  110 , arm  124 , and pad  132 , thereby directing the drill bit (not shown) into a desired trajectory. Pressure transducers  160 , if present, are able to report the pressure difference between first chamber  144  and second chamber  146  so that the operator or controller knows the amount of force applied to hybrid sleeve  104 . Furthermore, proximity detector  164  and magnet  162 , if present, are able to report the absolute position of piston  110  so that controller or operator knows the amount of deflection experienced by hybrid sleeve  104 .  
         [0026]     Referring briefly to  FIG. 3 , piston  110  is shown displaced to the left, thus placing a “negative” bias upon hybrid sleeve  104 . To displace piston  110  in this manner, high-pressure drilling fluid enters second chamber  146  as high-pressure port B is opened and high-pressure port A is closed. Simultaneously, low-pressure port C is opened and low-pressure port D is closed to allow first chamber  144  to communicate with the low-pressure annular drilling fluids of through manifold  138  and port  140 . High-pressure fluids are thus allowed to enter second chamber  146  and press against face  120  to deflect piston  110  to the left, in a “negative” direction of travel. The displacement of piston  110  to the left thus allows force to be transmitted from piton  110  through first arm  122  and first pad  130  to hybrid sleeve  104 . As before, pressure transducers  160 , and magnetic sensors  162 ,  164 , if present, allow a controller, or an operator to monitor the load and displacement of hybrid sleeve  104  resulting from bi-directional actuator assembly  100 .  
         [0027]     Referring now to  FIG. 4 , a bi-directional piston actuator assembly  200  with an integrated membrane shield system is shown. Piston actuator assembly  200 , like assembly  100 , includes a piston  210  that reciprocates within a seal bore  212  between two stops  214 ,  216 . Because the operating fluid of piston  110  is drilling fluid, problems with wear and abrasion of sealing surfaces often arises through frequent use. Drilling fluid, as a slurry composition, includes many solid and particulates within the fluid itself. These particulates can often be of elevated hardness and can scratch or abrade seal bore  212  over time. Any such abrasions would severely limit the amount of force transferable from piston  210  to hybrid sleeve  104  through arms  222 ,  224 , severely reducing the effectiveness of piston actuator assembly ( 100  of  FIGS. 1-3 ). To overcome this problem, the present invention includes the addition of membrane shields  270 ,  272  within first and second pressure chambers  244 ,  246 . Membrane shields  270 ,  272  preferably extend, in a conical-like shape, from first and second stops  214 ,  216  to first and second arms  222 ,  224 , respectively. Membranes  270 , 272  are preferably constructed from a durable, wear resistant flexible material such as a reinforced elastomer. Membranes  270 ,  272 , in effect, create two new “clean” pressure chambers  274 ,  276  where a “clean” hydraulic fluid (or oil) is maintained against faces  218 ,  220  of piston  210 , seal  242 , and seal bore  212 . Clean hydraulic fluid within clean chambers  274 ,  276  will be free of particulates and impurities that would otherwise harm the integrity of seal  242 .  
         [0028]     In operation, valves A, B, C, and D are opened and shut as with actuator assembly  100  of  FIGS. 1-3  to deflect piston  210  either in a positive or negative direction. With membranes  270 .  272  and clean pressure chambers  274 .  276 . drilling fluids never come into contact with sensitive seal components. For example, in actuating piston to the right (positive direction), high-pressure drilling fluid is allowed to communicate with first chamber  244  through port A and low-pressure drilling fluid is allowed to communicate with second chamber  246  through port D, leaving ports B and C closed. The high-pressure fluid would build up in chamber  244  and would impact force and pressure upon membrane  270 , thus transferring the force and pressure thereupon to clean hydraulic fluid contained within clean chamber  274 . The elevated pressure of clean fluid within chamber  274  would thereby exert force upon face  218  and drive piston  210  to the right. Similarly, to drive piston  210  to the left (negative direction), ports B and C would be opened with ports A and D closed to aloe high-pressure fluid to flow into second chamber  246 . Fluid in chamber  246  would likewise press upon membrane  272  and transmit pressure to clean fluid in chamber  276 , thereby exerting force upon face  220  and displacing piston  210  to the left.  
         [0029]     Preferably high-pressure ports A and B are constructed so that the high-pressure flow of drilling fluid flowing into chambers  244 ,  246  does not impact membranes  270 ,  272  directly. Any direct impact of high-pressure drilling fluid thereupon could abrade away or tear membranes  270 ,  272 , thus sacrificing their integrity. To accomplish this, either ports A, and B can be constructed to direct flow of high-pressure fluids away from membranes  270 ,  272  or shields (not shown) can be constructed within chambers  244 ,  246  to direct the flow. As with actuator assembly  100  of  FIGS. 1-3 , pressure transducers  260 , and magnetic proximity components  262  and  264  can be employed to allow a controller or an operator to monitor the position of and forces upon hybrid sleeve  104 .  
         [0030]     Typical downhole actuator assemblies actuators to engage or disengage three kick pads about the periphery of the directional drilling tool. These traditional pads operate only in one direction and therefore are either engaged or disengaged. Therefore, the number of possible force conditions that are possible are limited to 6 non-zero states (2 3 −1 [all disengaged]−1 [all engaged=cancels out]=6). Actuators in accordance with the present invention are capable of 3 states each, positive engagement, negative engagement, and non-engagement. Furthermore, a drilling tool using a pair of actuators of the type describe above (preferably oriented 90° from each other) can obtain 8 different non-zero force states (3 2−1  [all disengaged]=8). By employing three bi-directional actuator assemblies, a drilling tool can likewise obtain 26 non-zero states. Therefore, a drilling tool using bi-directional actuator assemblies can obtain more control and precision with respect to steering the drill bit than a drilling tool with the same amount (or more) unidirectional actuators.  
         [0031]     Referring finally to  FIG. 5 , a two bi-directional actuator assembly arrangement  300  is shown schematically. Actuator arrangement  300  is shown using two actuator assemblies ( 100  of  FIGS. 1-3  or  200  of  FIG. 4 ) spaced 90° apart inside a hybrid sleeve  104 . Arrangement  300  preferably includes parallel bearing surfaces  380  that allow load pads  330 A,  330 B,  332 A, and  332 B to slide thereupon. Parallel bearing surfaces  380  are necessary to allow hybrid sleeve  104  to move relative to drilling tool (not shown) freely and to prevent the arms  322 A,  324 A of one axis from restricting the arms  322 B,  324 B of another axis. This arrangement allows hybrid sleeve  104  to be manufactured of a relatively inflexible material, thereby maintaining its rigidity and strength.  
         [0032]     Numerous embodiments and alternatives thereof have been disclosed. While the above disclosure includes the best mode belief in carrying out the invention as contemplated by the named inventors, not all possible alternatives have been disclosed. For that reason, the scope and limitation of the present invention is not to be restricted to the above disclosure, but is instead to be defined and construed by the appended claims.

Summary:
Methods and apparatuses to direct a drill bit of a directional drilling assembly are disclosed. The methods and apparatuses employ the use of bi-directional actuators that are capable of displacing a hybrid steering sleeve in positive and negative directions. The bi-directional actuators are capable of greater control and precision in their actuations than traditional “engaged-disengaged” unidirectional actuators, thereby allowing for more precise directional drilling operations. The bi-directional actuators are preferably driven by drilling fluids and may optionally be shielded to lessen the erosive effects thereof.