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BACKGROUND OF THE DISCLOSURE 
       [0001]    The present disclosure relates generally to the field of drilling welts and more particularly to steerable drilling tools. 
         [0002]    In deviated and horizontal drilling applications it is advantageous to use rotary steerable systems to prevent pipe sticking in the deviated and horizontal sections. It is advantageous to have the drill string rotating to prevent differential sticking and to reduce friction with the borehole wall. The rotary steerable system may have a housing that is substantially non-rotating. The present disclosure describes a downhole adjustable bent housing for rotary steerable drilling. 
         [0003]    Directional drilling involves varying or controlling the direction of a wellbore as it is being drilled. Usually the goal of directional drilling is to reach or maintain a position within a target subterranean destination or formation with the drilling string. For instance, the drilling direction may be controlled to direct the wellbore towards a desired target destination, to control the wellbore horizontally to maintain it within a desired payzone or to correct for unwanted or undesired deviations from a desired or predetermined path. 
         [0004]    Thus, directional drilling may be defined as deflection of a wellbore along a predetermined or desired path in order to reach or intersect with, or to maintain a position within, a specific subterranean formation or target. The predetermined path typically includes a depth where initial deflection occurs and a schedule of desired deviation angles and directions over the remainder of the wellbore. Thus, deflection is a change in the direction of the wellbore from the current wellbore path. 
         [0005]    It is often necessary to adjust the direction of the wellbore frequently while directional drilling, either to accommodate a planned change in direction or to compensate for unintended or unwanted deflection of the wellbore. Unwanted deflection may result from a variety of factors, including the characteristics of the formation being drilled, the makeup of the bottomhole drilling assembly and the manner in which the wellbore is being drilled. 
         [0006]    Deflection is measured as an amount of deviation of the wellbore from the current wellbore path and is expressed as a deviation angle or hole angle. Commonly, the initial wellbore path is in a vertical direction. Thus, initial deflection often signifies a point at which the wellbore has deflected off vertical. As a result, deviation is commonly expressed as an angle in degrees from the vertical. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0007]      FIG. 1  shows a schematic diagram of a drilling system; 
           [0008]      FIG. 2A  shows a steerable drilling assembly; 
           [0009]      FIG. 2B  shows the steerable drilling, assembly of  FIG. 2  with a deviated steering shaft for altering the drilling direction; 
           [0010]      FIG. 3A  shows a section of the steerable assembly with the steering shaft aligned with the housing; 
           [0011]      FIG. 3B  shows an end view of the assembly of  FIG. 3A ; 
           [0012]      FIG. 4A  shows the section of the steerable assembly of  FIG. 3A  with the rotation of the orienting assemblies and the orienting sleeve to create a deviation angle between the steering shaft and the housing; 
           [0013]      FIG. 4B  is an end view of the assembly of  FIG. 4A ; and 
           [0014]      FIG. 5  is a block diagram of one embodiment of a steerable drilling apparatus. 
       
    
    
       [0015]    While the disclosed embodiments are susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. It should be understood, however, that the drawings and detailed description herein are not intended to limit the disclosed subject matter to the particular form(s) disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the scope of the present disclosure as defined by the appended claims. 
       DETAILED DESCRIPTION 
       [0016]    The illustrative embodiments described below are meant as examples and not as limitations on the claims that follow. 
         [0017]      FIG. 1  shows a schematic diagram of a drilling system  110  having a downhole assembly according to one embodiment of the present disclosure. As shown, the system  110  includes a conventional derrick  111  erected on a derrick floor  112 , which supports a rotary table  114  that is rotated by a prime mover (not shown) at a desired rotational speech. A drill string  120  that includes a drill pipe section  122  extends downward from rotary table  114  into a directional borehole  126 , also called a wellbore. Borehole  126  may travel in a three-dimensional path. The three-dimensional direction of the bottom  151  of borehole  126  is indicated by a pointing vector  152 . A drill bit  150  is attached to the downhole end of dull string  120  and disintegrates the geological formation  123  when drill bit  150  is rotated. The drill string  120  is coupled to a drawworks  130  via a kelly joint  121 , swivel  128 , and line  129  through a system of pulleys (not shown). During the drilling operations, drawworks  130  may be operated to control the weight on bit  150  and the rate of penetration of drill string  120  into borehole  126 . The operation of drawworks  130  is well known in the art and is thus not described in detail herein. 
         [0018]    During drilling operations a suitable drilling fluid (commonly referred to in the art as “mud”)  131  from a mud pit  132  is circulated under pressure through drill string  120  by a mud pump  134 . Drilling fluid  131  passes from mud pump  134  into drill string  120  via fluid line  138  and kelly joint  121 . Drilling fluid  131  is discharged at the borehole bottom  151  through an opening in drill bit  150 . Drilling fluid  131  circulates uphole through the annular space  127  between drill string  120  and borehole  126  and is discharged into mud pit  132  via a return line  135 . A variety of sensors (not shown) may be appropriately deployed on the surface according to known methods in the art to provide information about various drilling-related parameters, such as fluid flow rate, weight on bit, hook load, etc. 
         [0019]    A surface control unit  140  may receive communications, via a telemetry link, from downhole sensors and devices. The communications may be detected by a sensor  143  placed in fluid line  138  and processed according to programmed instructions provided to surface control unit  140 . Surface control unit  140  may display desired drilling parameters and other information on a display/monitor  142  which may be used by an operator to control the drilling operations. Surface control unit  140  may contain a computer, memory for storing data and instructions, a data recorder and other peripherals. Surface control unit  140  may also include well plan and evaluation models and may process data according to programmed instructions, and respond to user commands entered through a suitable input device., such as a keyboard (not shown). 
         [0020]    In one example, a steerable drilling bottom hole assembly (BHA)  159  may comprise dill collars and/or drill pipe, a measurement while drilling system  158 , and a steerable assembly  160 . MWD system  158  comprises various sensors to provide information about the formation  123  and downhole drilling parameters. MWD sensors  164  in BHA  159  may include, but are not limited to, a device for measuring the formation resistivity near the drill bit a gamma ray device for measuring the formation gamma ray intensity, devices for determining the inclination and azimuth of the drill string, and pressure sensors for measuring, drilling, fluid pressure downhole. The above-noted devices may transmit data to a downhole transmitter  133 , which in turn transmits the data uphole to the surface control unit  140 , via sensor  143 . In one embodiment, a mud pulse telemetry technique may be used to communicate data from downhole sensors and devices during drilling operations. A pressure transducer  143  placed in the mud supply line  138  detects mud pulses representative of the data transmitted by the downhole transmitter  133 . Transducer  143  generates electrical signals in response to the mud pressure variations and transmits such signals to surface control unit  140 . Alternatively, other telemetry techniques such as electromagnetic and/or acoustic techniques or any other suitable technique known in the art may be utilized. In one embodiment, hard-wired drill pipe may be used to communicate between the surface and downhole devices. In one example, combinations of the techniques described may be used. In one embodiment, a surface transmitter  180  transmits data and/or commands to the downhole tools using an of the transmission techniques described, for example a mud pulse telemetry technique. This may enable two-way communication between surface control unit  140  and a downhole controller  601  described below. 
         [0021]    BHA  159  may also comprise a steerable assembly  160  for directing a steering shaft  75  attached between the rotating BHA  159  and hit  150  along the desired direction to steer the path of the well. 
         [0022]    Referring to  FIGS. 2A-2B , a steerable drilling apparatus  160  is positioned near bit  150  in BHA  159 . Steerable drilling assembly  160  comprises rotatable drive shaft  195  coupled to a rotating member  191  of drill string  120 . Rotatable drive shaft  195  is coupled to a rotating steering shaft  75  by a coupling member  80 . Rotating steering shaft  75  is, in turn, coupled to drill bit  150  for drilling the wellbore  126 . As such, rotation of rotating, member  191  causes drill it  150  to rotate. In one example, rotating member  191  may be a drill string component that rotates at the same speed as the drill string. Alternatively, rotating member  191  may be the output shaft of a drilling motor disposed in drill string  120 , such that rotating member  191  rotates at an increased RPM equal to the motor output RPM plus the drill string RPM. 
         [0023]    As shown, orienting sleeve  50  is rotatably supported between a first orienting assembly  220 A and a second orienting assembly  220 B disposed within a substantially tubular housing  46 . Housing  46  is substantially rotationally stationary in the wellbore during drilling. Rotatable steering shaft  75  is rotatably supported in orienting sleeve  50 . Orienting sleeve  50  is also rotatable with respect to each orienting assembly  220 A,B by actuation of orienting, sleeve actuator  226 . Actuation of first orienting assembly  220 A, second orienting assembly  220 B, and orienting sleeve actuator  226  acts to orient steering shaft  75  and bit  150  in a desired three dimensional direction  252  to control the path of borehole  126 . 
         [0024]    First orienting assembly  220 A and second orienting assembly  220 B are disposed within housing  46  for controlling orienting sleeve  50 . Steering shaft  75  rotates within orienting sleeve  50 . Orienting sleeve  50  may be oriented to change the direction of steering shaft  75 . Orienting sleeve  50  may provide contact bearing support to steering shaft  75  to limit the bending and bending stresses imposed on steering shaft  75 , as described below. 
         [0025]    With reference to  FIGS. 3A-4B , orienting assembly  220 A comprises a circular outer ring  45 A that is rotatably supported by bearings  59 , on a circular inner peripheral surface  51  of housing  46 . Note in  FIGS. 3B and 4B  that the bearings  59  are omitted for clarity. Outer ring  45 A has a circular inner peripheral surface  56 A that is eccentric with respect to inner peripheral surface  51  of housing  46 . Circular inner peripheral surface  56 A of outer ring  45 A rotatably supports orienting sleeve  50  through bearings  59 . Similarly, orienting assembly  220 B comprises a circular outer ring  458  that is rotatably supported by bearings  59 , on circular inner peripheral surface  51  of housing  46 . Outer ring  45 B has a circular inner peripheral surface  56 B that is eccentric with respect to inner peripheral surface  51  of housing  46 . Circular inner peripheral surface  56 B of outer ring  45 B rotatably supports orienting sleeve  50  through bearings  59 . 
         [0026]    Orienting sleeve  50  has an inner peripheral surface  65  that defines an angled longitudinal circular bore  65  which has a centerline CL 3  that is angled with respect to a centerline CL 2  defined by the outer peripheral surface  66  of orienting sleeve  50  by a predetermined angle, θ (shown in  FIG. 4A ). By rotating outer rings  45 A,B and the orienting sleeve  50  relative to each other, and relative to housing  46 , shaft  75  may be inclined by angle, θ, such that bit  150  drills in a direction  152 ′ with respect to the borehole centerline, CL 1 , of housing  46 . in the embodiment shown, orienting assemblies  220 A,B also comprise a motors  25 A,B driving a spur gears  27 A,B that engages ring gears  26 A,B. Ring gears  26 A,B are attached to outer rings  45 A,B and controllably drive outer rings  45 A,B under the direction of a downhole controller  601 , discussed below. 
         [0027]    Orienting sleeve  50  may be controllably rotated relative to housing  46  and each outer ring  45 A,B by orienting sleeve actuator  226 . Orienting sleeve actuator  226  comprises a motor  30  driving a spur gear  31  that is operatively engaged with a ring gear  32  attached to outer peripheral surface  66  of orienting sleeve  50 . Motor  30  controllably rotates deflection sleeve  50  under the control of controller  601 . Motors  25 A,  25 B, and  30  may be electric motors, hydraulic motors, or combinations thereof Such motors may incorporate rotational sensors,  607 ,  608 , and  615 , respectively, for accurate determination of the rotational angular orientation of the outer rings  45 A,B and deflection sleeve  50  relative to housing  46 . 
         [0028]    The rotational orientation of drilling shaft  75  may be referenced as a toolface angle with respect to the gravitational high side of an inclined wellbore. Alternatively, in a substantially vertical wellbore, the reference may be to a north reference, for example magnetic, true, or grid north. As used herein, the toolface angle is the angle between the discussed reference, high side or north, and the plane containing the angled drilling shaft. 
         [0029]    As indicated above, orienting sleeve  50  may provide contact bearing support to steering shall  75  to limit the bending and bending stresses imposed on steering shaft  75 . In one example, the inner peripheral surface  65  of orienting sleeve  50  may be coated with an abrasion resistant coating  95  to act as a wear resistant bearing surface. Such a coating  95  may extend over the entire length of orienting sleeve  50 . Alternatively, the coating  95  may extend over predetermined portions of inner peripheral surface  65 . Abrasion resistant coating  95  may comprise. at least one of, a natural diamond coating, a synthetic diamond coating, a tungsten coating, a tungsten carbide coating, and combinations thereof. Similarly, at least some portions of steering shaft  75  may be coated For example, the peripheral surface of steering shaft  75  may be coated where they are operationally juxtaposed with coated bearing surfaces on the inner peripheral surface of  65  of orienting sleeve  50 . 
         [0030]    Downhole controller  601 , see  FIG. 5 , may be located in housing  46  to control the operation of steerable assembly  160 . Controller  601  may comprise a processor  695  in data communications with any of the orienting assemblies  220 A,B and  226  described above. In one embodiment, the deviation angle of drilling shaft  75  may be controlled by rotating the orientation sleeve  50  described above, and the toolface angle of drilling shaft  75  may be controlled with respect to the housing  46  by the proper rotation of outer rings  45 A,B, thus orienting the drill, bit  150  to drill along a desired path. 
         [0031]    In one example well trajectory models  697  may be stored in a memory  696  that is in data communications with a processor  695  in the electronics  601 . Directional sensors  692  may be mounted in housing  46  or elsewhere in the BHA, and may be used to determine the inclination, azimuth, and highside of the steering assembly  160 . Directional sensors may include, but are not limited to: azimuth sensors, inclination sensors, gyroscopic sensors, magnetometers, and three-axis accelerometers. Depth measurements may be made at the surface and/or downhole for calculating the location of steering assembly  160  along the wellbore  26 . If depth measurements are made at the surface, they may be transmitted to the downhole assembly using surface transmitter  180  described above with reference to  FIG. 1 . In operation, electronic interface circuits  693  may distribute power from power source  690  to one, or more, of directional sensors  692 , processor  695 , downhole transmitter  133 , first orienting assembly  220 , second orienting assembly  225 , and deflection sleeve actuator assembly  226 . In addition, electronic interface circuits  693  may transmit and/or receive data and command signals from directional sensors  692 , processor  695 . and telemetry system  691 . Angular rotation sensors  607 ,  608  and  615  may be used to determine the rotational positions of outer ring  45 A, outer ring  45 B, and orienting sleeve  75  relative to housing  46 . Power source  690  may comprise batteries, a downhole generator/alternator, and combinations thereof. In one embodiment, models  697  may comprise directional position models to control the steering assembly to control the direction of the wellbore along a predetermined trajectory. The predetermined trajectory may be 2-dimensional and/or 3-dimensional. In addition models  697  may comprise instructions that evaluate the readings of the directional sensors to determine when the well path has deviated from the desired trajectory. Models  697  may calculate and control corrections to the toolface and drilling shaft angle to make adjustments to the well path based on the detected deviations. In one example, models  697  may adjust the well path direction to move back to an original planned predetermined trajectory. In another, example, models  697  may calculate a new trajectory from the deviated position to the target, and control the steering assembly to follow the new path. in one example, the measurements, calculations, and corrections are autonomously executed downhole. Alternatively, direction sensor data may be transmitted to the surface, corrections calculated at the surface, and commands from the surface may be transmitted to the downhole tool to alter the settings of the steering assembly. 
         [0032]    Numerous variations and modifications will become apparent to those skilled in the art. It is intended that the following claims be interpreted to embrace all such variations and modifications.

Summary:
A method for steering a well comprises disposing a first orienting assembly and a second orienting assembly spaced apart along a circular inner peripheral surface of a housing. An orienting sleeve is rotatably supported between the first orienting assembly and the second orienting assembly, The orienting sleeve has an angled bore therethrough, wherein a first longitudinal axis of the angled bore is inclined by a predetermined angle to a second longitudinal axis referenced to a cylindrical outer peripheral surface of the orienting sleeve. A rotatable steering shaft is rotatably supported along the angled bore to control rotatable steering shaft bending. The rotation of the first orienting assembly, the second orienting assembly, and the orienting sleeve is controllably adjusted to control the steering direction of the rotatable steering shaft.