Patent Publication Number: US-11396775-B2

Title: Rotary steerable drilling assembly with a rotating steering device for drilling deviated wellbores

Description:
CROSS REFERENCES TO RELATED APPLICATIONS 
     The present application claims priority to U.S. application Ser. No. 15/210,669, filed Jul. 14, 2016, the contents of which are incorporated herein by reference in their entirety. 
     BACKGROUND 
     1. Field of the Disclosure 
     The disclosure relates generally to rotary drilling systems for drilling of deviated wellbores and particularly to a drilling assembly that utilizes a rotating steering device for drilling deviated wellbores. 
     2. Background Art 
     Wells or wellbores are formed for the production of hydrocarbons (oil and gas) from subsurface formation zones where such hydrocarbons are trapped. To drill a deviated wellbore, a drilling assembly (also referred to as a bottomhole assembly or “BHA”) that includes a steering device coupled to the drill bit is used. The steering device tilts a lower portion of the drilling assembly by a selected amount and along a selected direction to form the deviated portions of the wellbore. Various types of steering devices have been proposed and used for drilling deviated wellbores. The drilling assembly also includes a variety of sensors and tools that provide a variety of information relating to the earth formation and drilling parameters. 
     In one such steering device, an actuator mechanism is used in which a rotary valve diverts the mud flow towards a piston actuator, while the entire tool body, together with the valve, is rotating inside the wellbore. In such a mechanism, the valve actuation is controlled with respect to the momentary angular position inside the wellbore (up, down, left, right). A control unit maintains a rotary stationary position (also referred to as geostationary) with respect to the wellbore. As an example, if, during drilling, the drill string and thus the drilling assembly rotates at 60 rpm clockwise, the control unit rotates at 60 rpm counterclockwise, driven by, for example, an electric motor. To maintain a rotary stationary position, the control unit may contain navigational devices, such as accelerometer and a magnetometer. In such systems, the actuation force relies on the pressure drop between the pressure inside the tool and the annular pressure outside the tool. This pressure drop is highly dependent on operating parameters and varies over a wide range. The actuation stroke is a reaction based upon the pressure force exerted onto the actuation pistons. Neither force nor stroke is precisely controllable. 
     The disclosure herein provides a drilling system that utilizes a steering device that utilizes actuators that rotate along with the drilling assembly to drill deviated wellbores. 
     SUMMARY 
     In one aspect, a drilling assembly for use in drilling of a wellbore is disclosed. The drilling assembly includes a steering device having a tilt device and an actuation device, wherein a first section and a second section of the drilling assembly are coupled through the tilt device and wherein the first section is attached to a drill bit. The actuation device comprises an electromechanical actuator and causes a tilt of the tilt device to cause the first section attached to the drill bit and the drill bit to tilt relative to the second section along a selected first direction while the steering unit is rotating. 
     In another aspect, a method of drilling a wellbore is disclosed. A drilling assembly is conveyed in the wellbore. The drilling assembly includes a drill bit at an end thereof, a steering unit that includes a tilt device and an actuation device, wherein a first section and a second section of the drilling assembly are coupled through the tilt device and wherein the first section is attached to the drill bit, and wherein the actuation device comprises an electromechanical actuator and tilts the tilt device to cause the first section attached to the drill bit and the drill bit to tilt relative to the second section about the tilt device along a selected direction while the steering unit is rotating. The wellbore is drilled using the drill bit. The electromechanical actuator is actuated to tilt the tilt device to cause the first section attached to the drill bit and the drill bit to tilt relative to the second section and to maintain the tilt geostationary while the drilling assembly is rotating to form a deviated section of the wellbore. 
     Examples of the certain features of an apparatus and methods have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features that will be described hereinafter and which will form the subject of the claims. 
    
    
     
       DRAWINGS 
       For a detailed understanding of the apparatus and methods disclosed herein, reference should be made to the accompanying drawings and the detailed description thereof, wherein like elements are generally given same numerals and wherein: 
         FIG. 1  shows a schematic diagram of an exemplary drilling system that may utilize a steering unit for drilling deviated wellbores, according to one non-limiting embodiment of the disclosure; 
         FIG. 2  shows an isometric view of certain elements of an electro-mechanical steering device coupled to a drill bit for drilling deviated wellbores, according to a non-limiting embodiment of the disclosure; 
         FIG. 3  shows an isometric view of a non-limiting embodiment of an adjuster for use in the steering unit of  FIG. 2 ; 
         FIG. 4  shows certain elements of a modular electro-mechanical actuator for use in the steering unit of  FIG. 2 , according to a non-limiting embodiment of the disclosure; 
         FIG. 5  shows an isometric view of components of the steering unit laid out for assembling the steering unit of  FIG. 2 ; 
         FIG. 6  is a block diagram of a drilling assembly that utilizes a steering device having an actuation de vice and a hydraulic force application device, according to a non-limiting embodiment of the disclosure. 
         FIG. 7  shows both an assembled view and an exploded view of the drilling assembly for drilling deviated wellbore; 
         FIG. 8  shows both a side view and a cross-sectional view of the drilling assembly in a non-actuated configuration; 
         FIG. 9  shows a cross-section view of the drilling assembly in an actuated configuration; 
         FIG. 10  illustrates an assembly process for a joint; 
         FIG. 11  shows a cutaway view of the joint; 
         FIG. 12  shows a cross-sectional view of the joint showing an internal lubricant chamber; and 
         FIG. 13 a -13 c    show various positions of the joint relative to a stabilizer. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 1  is a schematic diagram of an exemplary rotary steerable drilling system  100  that utilizes a steering device (also referred to as steering unit or steering assembly) in a drilling assembly for drilling vertical and deviated wellbores and maintain the steering device geostationary or substantially geostationary while the steering device is rotating. A deviated wellbore is any wellbore that is non-vertical. The drilling system  100  is shown to include a wellbore  110  (also referred to as a “borehole” or “well”) being formed in a formation  119  that includes an upper wellbore section  111  with a casing  112  installed therein and a lower wellbore section  114  being drilled with a drill string  120 . The drill string  120  includes a tubular member  116  that carries a drilling assembly  130  (also referred to as the “bottomhole assembly” or “BHA”) at its bottom end. The tubular member  116  may be a drill pipe made up by joining pipe sections. The drilling assembly  130  is coupled to a disintegrating device, such as a drill bit  155 ) or another suitable cutting device, attached to its bottom end. The drilling assembly  130  also includes a number of devices, tools and sensors, as described below. The drilling assembly  130  further includes a steering device  150  to steer a section of the drilling assembly  130  along any desired direction, a methodology often referred to as geosteering. The steering device  150 , in one non-limiting embodiment, includes a tilt device  161  and an actuation device  160  (for example, an electro-mechanical device or a hydraulic device) that tilts one section, such as the lower section  165  of the drilling assembly  130 , relative to another section, such as the upper section  166  of the drilling assembly  130 . The lower section  165  is coupled to the drill bit  155 . In general, the actuation device tilts the tilt device  161 , which in turn causes the lower section  165  and thus the drill bit  155  to tilt or point a selected extent along a desired or selected direction, as described in more detail in reference to  FIGS. 2-6 . 
     Still referring to  FIG. 1 , the drill string  120  is shown conveyed into the wellbore  110  from an exemplary rig  180  at the surface  167 . The exemplary rig  180  in  FIG. 1  is shown as a land rig for ease of explanation. The apparatus and methods disclosed herein may also be utilized with offshore rigs. A rotary table  169  or a top drive  169   a  coupled to the tubular member  116  may be utilized to rotate the drill string  120  and the drilling assembly  130 . A control unit (also referred to as a “controller” or “surface controller”)  190 , which may be a computer-based system, at the surface  167  may be utilized for receiving and processing data transmitted by various sensors and tools (described later) in the drilling assembly  130  and for controlling selected operations of the various devices and sensors in the drilling assembly  130 , including the steering device  150 . The surface controller  190  may include a processor  192 , a data storage device (or a computer-readable medium)  194  for storing data and computer programs  196  accessible to the processor  192  for determining various parameters of interest during drilling of the wellbore  110  and for controlling selected operations of the various tools in the drilling assembly  130  and those of drilling of the wellbore  110 . The data storage device  194  may be any suitable device, including, but not limited to, a read-only memory (ROM), a random-access memory (RAM), a flash memory, a magnetic tape, a hard disc and an optical disk. To drill the wellbore  110 , a drilling fluid  179  is pumped under pressure into the tubular member  116 , which fluid passes through the drilling assembly  130  and discharges at the bottom  110   a  of the drill bit  155 . The drill bit  155  disintegrates the formation rock into cuttings  151 . The drilling fluid  179  returns to the surface  167  along with the cuttings  151  via annular space  127  (also referred as the “annulus”) between the drill string  120  and the wellbore  110 . 
     Still referring to  FIG. 1 , the drilling assembly  130  may further include one or more downhole sensors (also referred to as the measurement-while-drilling (MWD) sensors and logging-while-drilling (LWD) sensors or tools, collectively referred to as downhole devices  175 , and at least one control unit or controller  170  for processing data received from the downhole devices  175 . The downhole devices  175  may include sensors for providing measurements relating to various drilling parameters, including, but not limited to, vibration, whirl, stick-slip, flow rate, pressure, temperature, and weight-on-bit. The drilling assembly  130  further may include tools, including, but not limited to, a resistivity tool, an acoustic tool, a gamma ray tool, a nuclear tool and a nuclear magnetic resonance tool. Such devices are known in the art and are thus not described herein in detail. The drilling assembly  130  also includes a power generation device  186  and a suitable telemetry unit  188 , which may utilize any suitable telemetry technique, including, but not limited to, mud pulse telemetry, electromagnetic telemetry, acoustic telemetry and wired pipe. Such telemetry techniques are known in the art and are thus not described herein in detail. Drilling assembly  130 , as mentioned above, includes the steering device  150  that enables an operator to steer the drill bit  155  in desired directions to drill deviated wellbores when the drilling assembly is rotating and to maintain the steering device geostationary or substantially geostationary. Stabilizers, such as stabilizers  162  and  164  are provided along the lower section  165  and the upper section  166  to stabilize the steering device  150  and the drill bit  155 . Additional stabilizers may be used to stabilize the drilling assembly  130 . The controller  170  may include a processor  172 , such as a microprocessor, a data storage device  174 , such as a solid-state memory, and a program  176  accessible to the processor  172 . The controller  170  communicates with the surface controller  190  to control various functions and operations of the tools and devices in the drilling assembly. During drilling, the steering device  150  controls the tilt and direction of the drill bit  155 , as described in more detail in reference to  FIGS. 2-6 . 
       FIG. 2  shows an isometric view of certain elements or components of the steering device  150  for use in a drilling assembly, such as drilling assembly  130  of  FIG. 1 , to steer or tilt the drill bit  155  for drilling deviated wellbores, according to one non-limiting embodiment of the disclosure. The drilling assembly  130  includes a collar or housing  210  for housing the various elements or components of the steering device  150 . The steering device  150  includes a tilt device  161  and an actuation device  160  for tilting the lower section  165  with respect the upper section  166 . In one non-limiting embodiment, the tilt device  161  includes an adjuster  242  and a joint  244 . The upper section  166  and the lower section  165  are coupled by the joint  244 . The adjuster  242  is coupled to the joint  244  in a manner such that when the adjuster  242  is moved a certain amount along a certain direction, it causes the joint  244  to tilt accordingly. The tilt device  161  can be tilted by the actuation device  160  along any direction and by any desired amount to cause the lower section  165  and thus the drill bit  155  to point in any desired direction about a selected point or location in the drilling assembly  130 . The adjuster  242  may be a swivel or another suitable device. The joint  244  may be one of a Cardan joint, homokinetic joint, constant velocity joint, universal joint, knuckle joint, Hooke&#39;s joint, u-joint or another suitable device. The joint  244  transfers axial and torsional loads between the upper section  166  and the lower section  165 , while maintaining angular flexibility between the two sections. Stabilizers  162  and  164  are disposed at suitable locations around the steering device  150 , such as one around the lower section  165  and the other around the upper section  166 , to provide stability to the steering device  150  and the drill bit  155  during drilling operations. In one non-limiting embodiment, the actuation device  160  further includes a suitable number, such as three or more, of electro-mechanical actuators, such as actuators  222   a ,  222   b  and  222   c , radially arranged spaced apart in the actuation device  160 . Each such actuator is connected to a corresponding end  342   a - 342   c  ( FIG. 3 ) of the adjuster  242 . In one embodiment, each actuator is a longitudinal device having a lower end that can be extended and retracted to apply a desired force on the adjuster substantially parallel to a longitudinal axis  230  to cause the adjuster  242  to move about the longitudinal axis  230  of the steering device  150 . In  FIG. 2 , ends  224   a - 224   c  of actuators  222   a - 222   c  are shown directly connected respectively to the ends or abutting elements of the adjuster  242 . As described in reference to  FIG. 1 , the steering device  150  is part of the drilling assembly  130 . During drilling, as the drilling assembly  130  rotates, the steering device  150  and thus each actuator rotates therewith. Each actuator  222   a - 222   c  is configured to apply force on the adjuster  242 , as described later, and depending upon the forces applied, the movement of the adjuster  242  causes the lower section  165  and thus the drill bit  155  to tilt along a desired direction. In the embodiment shown in  FIG. 3 , since the actuators  222   a - 222   c  are mechanically connected to their corresponding adjuster ends  342   a - 342   c , the forces applied by such actuators and their respective strokes may be synchronized to create any desired steering direction. Although, the actuators  222   a - 222   c  shown apply axial forces on the adjuster  242 , any other suitable device, including, but not limited to a rotary oscillating device, may be utilized to apply forces on the adjuster  242 . In aspects, movement of at least a part the electro-mechanical actuation unit  220  may be selectively adjusted or limited (mechanically, such as by providing a stop in the steering device or electronically by a controller) to cause the lower section  165  to tilt with a selected tilt relative to the upper section  166 . Also, the tilt of the joint  244  may be selectively adjusted or limited to cause the lower section  165  to tilt with a selected tilt relative to the upper section  166 . 
       FIG. 3  shows an isometric view of non-limiting embodiment of an adjuster  242  for use in the steering device  150  of  FIG. 2 . Referring to  FIGS. 2 and 3 , the adjuster  242  includes a cylindrical body  342  and a number of spaced apart abutting elements or members, such as connectors  322   a ,  322   b  and  322   c , with connector  322   a  having one end  320   a  connected to the adjuster end  342   a  and the other end  324   a  for a direct connection to the actuator  222   a , connector  322   b  having one end  320   b  connected to the adjuster end  342   b  and the other  324   b  for direct connection to the actuator  222   b , and connector  322   c  having one end  320   c  connected to adjuster end  342   c  and the other end  324   c  for direct connection to the actuator  222   c . The abutting elements may include elements such as a cam, a crank shaft; an eccentric member; a valve; a ramp element; and a lever. In this configuration, when forces are applied onto the adjuster  242  by the actuators, the adjuster  242  may create an eccentric offset in real time in any desired direction by any desired amount about the longitudinal axis  230 , which provides 360 degrees of drill bit maneuvering ability during drilling. The forces on the connectors  322   a - 322   c  create a substantially geostationary tilt of the tilt device  161 . In an alternative embodiment, the adjuster  242  may be a hydraulic device that causes the joint  244  to tilt the lower section  165  relative to the upper section  166 , as described in more detail in reference to  FIG. 6 . 
       FIG. 4  shows certain elements or components of an actuator  400  for use as any of the actuators  222   a - 222   c  in the steering device  150  of  FIG. 2 . In one aspect, the actuator  400  is a unitary device that includes a movable end  420  that may be extended and retracted. The actuator  400  further includes an electric motor  430  that may be rotated in clockwise and anticlockwise directions. The electric motor  430  drives a gear box  440  (clockwise or anti-clockwise) that in turn rotates a drive screw  450  and thus the movable end  420  axially in either direction. The actuator  400  further includes a control circuit  460  that controls the operation of the electric motor  430 . The control circuit  460  includes electrical circuits  462  and may include a microprocessor  464  and memory device  466  that houses instructions or programs for controlling the operation of the electric motor  430 . The control circuit  460  is coupled to the electric motor  430  via conductors through a bus connector  470 . In aspects, the actuator  400  may also include a compression piston device or another suitable device  480  for providing pressure compensation to the actuator  400 . Each such actuator may be a unitary device that is inserted into a protective housing disposed in the steering device  150  ( FIG. 1 ), as described in reference to  FIG. 5 . During drilling, each such actuator is controlled by its control circuit, which circuit may communicate with the controller  170  ( FIG. 1 ) and/or surface controller  190  ( FIG. 1 ) to exert force on the adjuster  242  ( FIG. 2 ). 
       FIG. 5  shows an isometric view  500  of components of the steering device  150  of  FIG. 2  laid out for assembling the steering device  150 . As described earlier, the steering device  150  includes an upper section  166 , a lower section  165 , an adjuster  242  and a joint  244  between the upper section  166  and the lower section  165 . The upper section  166  includes bores or pockets  520   a ,  520   b  and  520   c , corresponding to each of the individual actuators, such as actuators  222   a - 222   c . The actuator  222   a  is inserted into the bore or pocket  520   a , actuator  222   b  into bore or pocket  520   b  and actuator  222   c  into bore or pocket  520   c . The actuators  222   a - 222   c  are connected to the upper ends  342   a - 342   c  of the adjuster  242  as described above in reference to  FIGS. 2 and 3 . The adjuster  242  is connected to the lower section  165  by means of the joint  244  to complete the steering device. The steering device  150  is connected to the drill bit  155 . 
       FIG. 6  is a block diagram of a drilling assembly  200  that utilizes a steering device  250  that includes an actuation device  280  and a tilt device  270 . The actuation device  280  shown is the same as shown in  FIG. 2  and includes three or more actuators  280   a - 280   c  disposed in a housing  210 . The tilt device  270  includes an adjuster  277  and a joint  274 . In one non-limiting embodiment, the adjuster  277  includes a separate hydraulic force application device corresponding to each of the actuators  280   a - 280   c . In  FIG. 2 , force application devices  277   a - 277   c  respectively correspond to and are connected to actuators  280   a - 280   c . The actuators  280   a - 280   c  selectively operate their corresponding force application devices  277   a - 277   c  to tilt the lower section  258  relative to the upper section  246  about the joint  274  when the drilling assembly  200  and thus the steering device  250  is rotating. In one non-limiting embodiment, each of the force application devices  277   a - 277   c  includes a valve in fluid communication with pressurized drilling fluid  279  flowing through channel  289  in the drilling assembly  200  and a chamber that houses a piston. In the embodiment of  FIG. 6 , force application devices  277   a - 277   c  respectively include valves  276   a - 276   c  and pistons  278   a - 278   c  respectively disposed in chambers  281   a - 281   c . During drilling, the steering device  250  rotates while the pressurized drilling fluid  279  flows through channel  289  and exits through the passages or nozzles  255   a  in the drill bit  255 . The exiting fluid  279   a  returns to the surface via annulus  291 , which creates a pressure drop between the channel  289  and the annulus  291 . In aspects, the disclosure herein utilizes such a pressure drop to activate the hydraulic force application devices  277   a - 277   c  to create a desired tilt of the lower section  258  relative to the upper section  246  about the joint  274  and to maintain such tilt geostationary or substantially geostationary while the steering device  250  is rotating. To tilt the drill bit  255  via the lower section  258  and upper section  246 , the actuators  280   a - 280   c  selectively open and close their corresponding valves  276   a - 276   c , allowing the pressurized drilling fluid  279  from channel  289  to flow to the cylinders  281   a - 281   c  to extend pistons  278   a - 278   c  radially outward, which apply desired forces on the adjuster  277  to tilt the lower section  258  and thus the drill bit  255  along a desired direction. Each piston and cylinder combination may include a gap, such as gap  283   a  between piston  278   a  and cylinder  281   a  and gap  283   c  between piston  278   c  and chamber  281   c . Such a gap allows the fluid entering a chamber to escape from that chamber into the annulus  291  when the valve is open and the piston is forced back into its cylinder. Alternatively, one or more nozzles or bleed holes (not shown) connected between the cylinder and the annulus  291  may be provided to allow the fluid to flow from the chamber into the annulus  291 . To actively control the tilt of the lower section  258  while the rotary steerable drilling assembly  200  is rotating, the three or more valves  276   a - 276   c  may be activated sequentially and preferably with the same frequency as the rotary speed (frequency) of the drilling assembly  200 , to create a geostationary tilt between the upper section  246  and the lower section  258 . For instance, referring to  FIG. 6 , if an upward drilling direction is desired, the actuator  280   c  is momentarily opened, forcing the piston  278   c  to extend outward. At the same moment, actuator  280   a  would close valve  276   a , blocking pressure from the channel  289  to the piston  278   a . Since all pistons  276   a - 276   c  are mechanically coupled through the joint  274 , piston  278   a  would return or retract upon the outboard stroke of piston  278   c . When the drilling assembly  200  rotates, e.g. by 180° and for the case of four actuators distributed equi-spaced around the circumference of the drilling assembly  200 , the activation would reverse, actuator  280   a  opening valve  276   a  and actuator  280   c  closing valve  276   c , thus maintaining a geostationary tilt direction. Similar methods may be utilized to tilt and maintain the tilt geo stationary for the embodiment shown in  FIG. 2 . 
     Referring to  FIGS. 1-6 , the steering device  150  described herein is in the lower portion of a drilling assembly  130  ( FIG. 1 ) of a rotary drilling system  100 . The steering device  150  includes an adjuster and a joint connected to an actuation device that maneuvers or tilts the adjuster about a drilling assembly axis, which in turn tilts the joint. The joint tilts a lower section containing the drill bit relative to an upper section of the drilling assembly. The system transmits torque from a collar to the drill bit. In one non-limiting embodiment, the adjuster is actively tilted by a selected number of intermittently activated electro-mechanical actuators. The actuators rotate with the drilling assembly and are controlled by signal inputs from one or more position sensors in the drilling assembly  130 . Any suitable directional sensors, including, but not limited to magnetometers, accelerometer and gyroscopes may be utilized. Such sensors provide real time position information relating to the wellbore orientation while drilling. Depending on the type and the design of the adjuster the actuators may perform reciprocating or rotary oscillating movement, e. g., actuators coupled to a cam or crank system further enabling the eccentric offset in any desired direction from the drilling assembly axis during each revolution of the drilling assembly, creating a geostationary force and offset of the adjuster axis. 
     The drilling system  100  disclosed herein does not require a control unit to counter-rotate the tool body rotation. The modular activators positioned in the outer diameter of the actuation assembly receive command signals from a controller located in another section of the tool or higher up in the drilling assembly that may also include navigational sensors. These navigational sensors rotate with the drilling assembly. Such a mechanism can resolve and process the rotary motion of the drilling assembly to calculate momentary angular position (while rotating) and generate commands to the individual actuators substantially instantaneously. As an example, assume the drilling assembly rotates at ⅓ revolutions per second (20 rpm). The current steering vector is intended to point upwards. Assuming the side force element increases eccentricity with positive displacement of the actuation units, the navigational package electronics determine the momentary angular position of the drilling assembly or the steering unit with respect to the earthen formation and sends commands to all of the actuators (stroke and force). At time zero second, one of the actuators (for example the lowermost) receives a command to stroke outward a certain distance. At time 1 second, the steering unit has rotated 120 degrees and the same actuator receives the command to decrease the stroke to approximately to the middle position. At time 1.5 seconds, this actuator is at the uppermost position and the navigational package electronics sends a command to further decrease the stroke of a similar value as sent at zero second, but negative from a middle position. The commands are constantly sent to each actuator with their respective stroke requirements. With the changes for the stroke of the actuators, the angular tilt can be controlled and adjusted in real time. In such a configuration, each actuator performs one stroke per tool revolution (positive and negative from the middle position). To drill a straight wellbore section, all actuators are maintained stationary at their respective middle positions, thus requiring only minimum energy supply to hold the centralized position. The amount of the tilt angle and the momentary direction of the tilt angle controls the drilling direction of the wellbore. 
       FIG. 7  shows both an assembled view  702  and an exploded view  704  of the drilling assembly  130  for drilling deviated wellbores.  FIG. 8  shows both a side view  802  and a cross-sectional view  804  of the drilling assembly  130  in a non-actuated configuration. The outer components of the drilling assembly  130  are made transparent to reveal the internal components. The drilling assembly  130  includes an upper housing  710  having a string connector  719  on its upper or uphole end for attaching the upper housing  710  to uphole segments or tools of the BHA. The upper housing  710  further includes a shoulder thread  722  at its lower or downhole end. A drill bit  715  is coupled to the downhole end of the upper housing  710  via a joint  713  that is placed between the upper housing  710  and the drill bit  715 . The drill bit  715  connects to one end of the joint  713  and the upper housing  710  connects to an opposite end of the joint  713 . 
     The joint  713  includes a box thread  717  at its downhole end and a box thread  721  at its uphole end. The drill bit includes a drill bit thread  718 . The drill bit  715  is mechanically fastened to the joint  713  by threadingly attaching drill bit thread  718  to box thread  717 . The joint  713  is mechanically fastened to the upper housing by threadingly attaching the box thread  721  to shoulder thread  722 . A stabilizer  714  is clamped or bracketed between the joint  713  and the drill bit  715  and circumferentially surrounds drill bit thread  718  and box thread  717 . Similarly, an adjuster  712  is clamped or bracketed between the upper housing  710  and the joint  713  and circumferentially surrounds box thread  721  and shoulder thread  722 . One or more electromechanical actuators  711  extend through bores in the upper housing  710 . The electromechanical actuators  711  are linked to the adjuster  712  once the drilling assembly is in its assembled state. The adjuster  712  receives forces applied via the electromechanical actuators  711  to adjust an angle at the joint  713 . 
       FIG. 9  shows a cross-section view  900  of the drilling assembly  130  in an actuated configuration. A drilling assembly axis  728  and drill bit axis  729  are shown within the drilling assembly  130 . Drilling assembly axis  728  represents a central longitudinal axis of the BHA. Drill bit axis  729  represents a central longitudinal axis of the drill bit. The drill bit axis  729  indicates a direction in which the drill bit is drill bit pointed. In the actuated configuration, the drill bit axis  729  is angularly offset from the drilling assembly axis  728  (i.e., forms a non-zero angle with respect to the drilling assembly axis  728 ). Point  902  indicates a location at which the drilling assembly axis  728  and the drill bit axis  729  intersect when the drilling assembly  130  is actuated. The joint  713  allows for angular flexibility between drill bit  715  and upper housing  710  and allows drilling torque and axial force (weight on bit) to be transmitted from the upper housing  710  to the drill bit  715 . 
     The angular offset is created and dynamically adjusted using the electromechanical actuators  711  to apply a force against the adjuster  712 . Reciprocating movement of the electromechanical actuators  711  against the adjuster  712  generates a geostationary tilt angle between the drill bit axis  729  and the drilling assembly axis  728 . While the electromechanical actuators  711  have limited power output, they can transfer high load torques and high axial loads through the drilling assembly  130  due to having minimal or low friction between those load-bearing components which move during the reciprocating motion of the adjuster  712  and/or joint  713 . 
       FIG. 10  illustrates an assembly process for the joint  713 . A Cardan element  730  or universal joint element is provided. The Cardan element  730  includes four bolts  740  spaced at 90 degrees from each other around a circumference of the Cardan element  730 . Bearings  737  (which can be low friction roller bearings) are carried by or secured to each of the four bolts  740 . The four bolts  740  define two axes of the Cardan element  730 , both of which are shown perpendicular to each other. When the joint  713  is assembled, these axes are perpendicular to the longitudinal axis of upper connector  731  and lower connector  732 , and perpendicular to the longitudinal axis of drilling assembly  130 . The two axes of the Cardan element  730  allow lower connector  732  to pitch and yaw, respectively, relative to upper connector  731 . While having the axes perpendicular to each other and to the longitudinal axes of upper connector  731 , lower connector  732  and drilling assembly  130  is a preferred embodiment, this is not meant to be a limitation of the invention. Respective angles may also be smaller or larger than 90°. The Cardan element  730  is inserted into a lower connector  732  so that two opposing bolts of the Cardan element  730  reside within receiving holes  738   b  formed in arms  738   a  of the lower connector  732 . The Cardan element  730  is then inserted into an upper connector  731  so that the two remaining bolts reside within receiving holes  739   b  formed in arms  739   a  of the upper connector  731 . A bellows carrier sleeve  733  is then slid over the Cardan element  730  and arms  738   a  and  739   a . Finally, a bellows  734  is slid into place along the upper connector  731  to couple to the bellows carrier sleeve  733 . 
       FIG. 11  shows a cutaway view  1100  of the joint  713 . The upper connector  731  and the lower connector  732  are shown with the Cardan element  730  therebetween to allow angular rotation between the upper connector  731  and the lower connector  732 . Each bolt  740  is secured to center element  736  of Cardan element  730 . Center element  736  houses bearings  737 , such as plain bearings or roller bearings (comprising roller elements, for example, cylindrical, tapered or spherical rollers) that are joined to their respective bolts  740 . Cardan element  730  in combination with bearings  737  allow rotation of upper connector  731  and lower connector  732  about their respective longitudinal axes while simultaneously allowing transfer of torque from upper connector  731  to lower connector  732  and vice versa and transferring of axial load (also known as weight-on-bit) from upper connector  731  to lower connector  732  and vice versa. Since the forces, associated with torque and weight-on-bit are extremely high in drilling applications, the transfer of torque and weight-on-bit will create wear on bearings  737 . In one embodiment, the bearings  737  are roller bearings and the roller elements are substantially cylindrically symmetric (and not ball symmetric) elements, such as cylindrical, tapered, or frusto-conical rollers. Cylindrically symmetric roller elements have the benefit that forces associated with torque and weight-on-bit will be distributed over a larger area compared to spherical roller elements, for example, which results in less stress on the roller elements. However, cylindrical roller elements are generally not used in conjunction with ball joints. In contrast, cylindrical roller elements are used when upper connector  731  and lower connector  732  are connected via a Cardan-type connection, such as Cardan element  730 , that defines a pitch axis and a yaw axis that allow lower connector  732  to pitch and yaw, respectively, relative to upper connector  731 , with the axis of rotation for the cylindrical symmetrical roller elements are parallel to either the pitch axis or the yaw axis. 
     Drilling torque and axial load is transferred from the two arms  739   a  of the upper connector  731  into the respective bearings of the Cardan element  730  and further into the center element  736 . The center element  736  can have a cylindrical outer surface. Alternatively, the outer surface of the center element can include any number of adjoining planar surfaces. The center element  736  guides the load towards the bearings  737 . Drilling torque and axial load is thereby transferred from an upper connector  731  to the lower connector  732  through the bearings  737  via a center element  736  and respective bolts  740 . 
     As shown in  FIG. 11 , the bellows  734  includes an inner bellows  739  attached to the upper connector  731  and an outer bellows  734   a  coupled to the bellows carrier sleeve  733 . The bellows carrier sleeve  733  is coupled to the lower connector  732 . The bearings  737  of the joint  713  are sealed off from the environment via the bellows carrier sleeve  733  and bellows  734 , which allow angular movement between upper connector  731  and lower connector  732 . In one embodiment, an internal seal sleeve  735  through center element opening  736   a  of center element  736  of Cardan element  730  seals off an inside of the joint  713 . At the same time, internal sleeve  735  defines an opening through the center of Cardan element  730  that allows fluid, such as drilling fluid  179 ,  279  to flow through upper connector  731  and lower connector  732  to drill bit  155 ,  255  for cooling and lubrication purposes. The internal seal sleeve  735  can be designed with materials having a flexibility to allow for the angular deflection. For example, internal seal sleeve  735  can be made of at least one of titanium, plastic, PEEK, copper, alloys of aluminum, magnesium, or bronze, fiber carbon, or any combination of these. Outer diameter of joint  713  is defined by bellows carrier sleeve  733  and cannot be larger than diameter of borehole  110  that is defined by the diameter of drill bit  155 ,  255 . On the other hand, internal sleeve  735  needs a minimum outer diameter to provide for a minimum cross-sectional area that is large enough to allow sufficient drilling fluid flow through joint  713  to drill bit  155 ,  255 . In other words, the diameter of internal sleeve  735  needs to be large enough to provide for a flow resistance of drilling fluid that is low enough in order to effectively cool and lubricate drill bit  155 . The space between outer diameter of joint  713  and outer diameter of internal sleeve  735  can be utilized for substantially cylindrically symmetric roller elements. Longer cylindrical symmetrical roller elements are beneficial because forces associated with torque and weight-on-bit are distributed over a larger area compared to smaller roller elements, thereby resulting in less stress on the roller elements. However, since the axis of rotation of cylindrically symmetric roller elements is directed in a radial direction of joint  713 , the length of cylindrically symmetric roller elements is limited between outer diameter of joint  713  and outer diameter of internal sleeve  735 . For example, the length of cylindrically symmetric roller elements may be smaller than 33%, such as than 25% (e.g. smaller than 20% or 15%) of the outer diameter of joint  713 . 
       FIG. 12  shows a cross-sectional view of the joint  713  showing an internal lubricant chamber  742 . A lubricant (e.g., a bearing grease or oil) is stored within the lubricant chamber  742  and is sealed from the environment by the inner bellows  734   b , the outer bellows  734   a , the bellows carrier sleeve  733 , the upper connector  731 , the lower connector  732 , and the internal seal sleeve  735 . The lubricant allows for a low friction angle adjustment between drilling assembly axis  728  and drill bit axis  729 , even in the presence of high drilling torque and axial load. Sealing elements are installed to seal off the various components of joint  713  against each other. Angular movement of the joint  713  is facilitated by the degree of flexibility of the bellows  738  as well as by pressure compensation provided by the lubricant against the pressure of the fluid (i.e., drilling mud  741 ) outside of the joint  713 . While  FIG. 12  shows a pressure compensation system utilizing bellows to provide for pressure compensation, other pressure compensation systems, such as those utilizing a movable piston in response to a pressure difference, may be utilized as well for the same purpose. 
     The low amount of friction in joint  713 , in particular if lubricated roller bearings are used, enables the use of the electromechanical actuators to dynamically adjust and correct the axis angle. In downhole applications, electromechanical actuators are powered by either energy storage devices, for example batteries or capacitors, or by energy generated by flow of drilling fluid  179 ,  279  (for example using turbines), by rotation of tubular member  116  (such as drill pipe) and/or by vibration (e.g. by energy harvesting devices). Typically, the power that can be delivered by such technologies to a downhole location is relatively small. However, when low friction joints (e.g. low friction joints with roller bearings, such as lubricated roller bearings) are used, the power that can be delivered downhole is sufficient for the steering device disclosed herein. In one example, a force applied by one of the three electromechanical actuators  711  is about 1000 N with a respective stroke of approximately 20 mm to actuate the required axis offset of about 1° to create a curvature of about 15° per 100 feet. At a rotary speed of the drill string of approximately 180 rpm, each of the electromechanical actuators  711  performs 3 strokes per second. The actuation power for this example is less than 100 Watt for each actuator and can be provided by standard downhole energy-providing technologies as described above. 
       FIGS. 13 a -13 c    show a joint  1313  (such as joint  713 ) positioned relative to a stabilizer  1314  (such as stabilizer  714 ).  FIG. 13 a    shows joint  1313  at substantially the same position as stabilizer  1314 . In other words, the stabilizer blades of the stabilizer  1314  overlap the location  1302  at which the drilling assembly axis  1328  and the drill bit axis  1329  intersect when drilling assembly  1330  is actuated.  FIG. 13 b    shows joint  1313  positioned below or downhole of stabilizer  1314 , and  FIG. 13 c    shows joint  1313  positioned above or uphole of stabilizer  1314 . The position of stabilizer  1314  has several effects. In an embodiment, stabilizer  1314  protects joint  1313 , for example, Cardan element  730 , inner bellows  734   b , outer bellows  734   a , bellows carrier sleeve  733 , upper connector  731 , and lower connector  732  against wall contact to prevent damage to joint  1313 . The closer joint  1313  is to stabilizer  1314 , the more the joint  1313  is protected by stabilizer  1314 . In one embodiment, as illustrated in  FIGS. 13 b , 13 c   , stabilizer  1314  limits the space that is required to create the angular offset between drilling assembly axis  1328  and drill bit axis  1329 . When the distance between joint  1313  and drill bit  1315  is reduced, the dogleg severity (DLS), that can be achieved with an angle between drilling assembly axis  1328  and drill bit axis  1329 , is decreased as compared to the setup where the joint  1313  is substantially at the same position of the stabilizer  1314  or above the stabilizer  1314  (as shown in  FIG. 13 c   ) by the resulting smaller bit offset. However, as a result of the shorter distance (and the smaller bit offset) between the drill bit  1315  and the joint  1313 , the available side force at the drill bit  1315  for a given available power of the electromechanical actuator  711 , can be higher. A higher side force at the drill bit can be beneficial for initiating a curvature of the borehole from a substantially straight borehole or for more accurate directional control of the well path, especially when drilling in hard rock formation. In another aspect, a greater distance between drill bit  1315  and joint  1313 , at a position above the stabilizer  1314 , can be selected to create an angle between drilling assembly axis  1328  and drill bit axis  1329  at a position above (i.e., uphole of) stabilizer  1314 . Positioning the joint  1313  above (i.e., uphole of) the stabilizer  1314  can have the advantage of a reduction of forces of the electromechanical actuator  711  for certain relations of e. g. borehole diameter (or diameter of drill bit  1315 ), diameter of stabilizer  1314 , distance between stabilizer  1314  and drill bit  1315 , distance between drill bit  1315  and joint  1313 , or any combination thereof. In some configurations, the forces to drill a curved borehole can be minimal or even zero, thus reducing the power demand of the electromechanical actuators  711 . As shown in  FIG. 13 c   , the distance between the joint  1313  and the stabilizer  1314  is limited by geometrical constraints of the drilling assembly and the diameter of the borehole. In one embodiment, the distance between stabilizer  1314  and joint  1313  is 2 meters or less. In another embodiment, the angle between the drilling assembly axis  1328  and the drill bit axis  1329  is less than 2 degrees. In another embodiment, joint  1313  is located between stabilizer  1314  and drill bit  1315 . In another embodiment, joint  1313  and the stabilizer  1314  is substantially at location  1302  at which the drilling assembly axis  1328  and the drill bit axis  1329  intersect when drilling assembly  1330  is actuated. In some configurations, the stabilizer  1314  (or  714  in  FIG. 9 ) tilts with the drill bit axis  1329 . 
     The foregoing disclosure is directed to the certain exemplary non-limiting embodiments. Various modifications will be apparent to those skilled in the art. It is intended that all such modifications within the scope of the appended claims be embraced by the foregoing disclosure. The words “comprising” and “comprises” as used in the claims are to be interpreted to mean “including but not limited to”. Also, the abstract is not to be used to limit the scope of the claims.