Abstract:
A drill bit direction system and method is disclosed that modifies or biases the stochastic movement of the drill bit to change a drilling direction of a drilling system. The direction of the drill bit is monitored to determine if the direction happens to align in some way with a preferred direction. If the direction isn&#39;t close enough to a preferred or desired direction, stochastic motion of the drill bit in the borehole may be controlled and/or motion of the drill bit under a side force acting on the drill bit to direct the drilling may be focused or biased to modify the direction of drilling closer to the preferred direction. Any of a number of stochastic motion control mechanisms or biasing mechanisms can be used. Some embodiments can resort to conventional steering mechanisms to supplement the stochastic motion control or side force biasing mechanisms.

Description:
This application claims the benefit of and is a continuation-in-part of co-pending U.S. application Ser. No. 11/839,381 filed on Aug. 15, 2007, entitled SYSTEM AND METHOD FOR CONTROLLING A DRILLING SYSTEM FOR DRILLING A BOREHOLE IN AN EARTH FORMATION, which is hereby expressly incorporated by reference in its entirety for all purposes. 
     This application is related to the U.S. patent application Ser. No. 12/116,380, filed May 7, 2008, on the same date as the present application, entitled “STOCHASTIC BIT NOISE CONTROL”, now U.S. Pat. No. 8,066,085 issued Nov. 29, 2011, which is incorporated by reference in its entirety for all purposes. 
     This application is related to U.S. patent application Ser. No. 12/116,390, filed May 7, 2008, on the same date as the present application, entitled “DRILL BIT GAUGE PAD CONTROL”, which is incorporated by reference in its entirety for all purposes. 
     This application is related to U.S. patent application Ser. No. 12/116,408, filed May 7, 2008, on the same date as the present application, entitled “SYSTEM AND METHOD FOR DIRECTIONALLY DRILLING A BOREHOLE WITH A ROTARY DRILLING SYSTEM”, which is incorporated by reference in its entirety for all purposes. 
    
    
     BACKGROUND 
     This disclosure relates in general to drilling a borehole and, but not by way of limitation, to controlling direction of drilling for the borehole. 
     In many industries, it is often desirable to directionally drill a borehole through an earth formation or core a hole in sub-surface formations in order that the borehole and/or coring may circumvent and/or pass through deposits and/or reservoirs in the formation to reach a predefined objective in the formation and/or the like. When drilling or coring holes in sub-surface formations, it is sometimes desirable to be able to vary and control the direction of drilling, for example to direct the borehole towards a desired target, or control the direction horizontally within an area containing hydrocarbons once the target has been reached. It may also be desirable to correct for deviations from the desired direction when drilling a straight hole, or to control the direction of the hole to avoid obstacles. 
     In the hydrocarbon industry for example, a borehole may be drilled so as to intercept a particular subterranean-formation at a particular location. In some drilling processes, to drill the desired borehole, a drilling trajectory through the earth formation may be pre-planned and the drilling system may be controlled to conform to the trajectory. In other processes, or in combination with the previous process, an objective for the borehole may be determined and the progress of the borehole being drilled in the earth formation may be monitored during the drilling process and steps may be taken to ensure the borehole attains the target objective. Furthermore, operation of the drill system may be controlled to provide for economic drilling, which may comprise drilling so as to bore through the earth formation as quickly as possible, drilling so as to reduce bit wear, drilling so as to achieve optimal drilling through the earth formation and optimal bit wear and/or the like. 
     One aspect of drilling is called “directional drilling.” Directional drilling is the intentional deviation of the borehole/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 in offshore drilling because it enables many 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 used in vertical drilling operation as well. 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. 
     The monitoring process for directional drilling of the borehole may include determining the location of the drill bit in the earth formation, determining an orientation of the drill bit in the earth formation, determining a weight-on-bit of the drilling system, determining a speed of drilling through the earth formation, determining properties of the earth formation being drilled, determining properties of a subterranean formation surrounding the drill bit, looking forward to ascertain properties of formations ahead of the drill bit, seismic analysis of the earth formation, determining properties of reservoirs etc. proximal to the drill bit, measuring pressure, temperature and/or the like in the borehole and/or surrounding the borehole and/or the like. In any process for directional drilling of a borehole, whether following a pre-planned trajectory, monitoring the drilling process and/or the drilling conditions and/or the like, it is necessary to be able to steer the drilling system. 
     Forces which act on the drill bit during a drilling operation include gravity, torque developed by the bit, the end load applied to the bit, and the bending moment from the drill assembly. These forces together with the type of strata being drilled and the inclination of the strata to the bore hole may create a complex interactive system of forces during the drilling process. 
     The drilling system may comprise a “rotary drilling” system in which a downhole assembly, including a drill bit, is connected to a drill-string that may be driven/rotated from the drilling platform. In a rotary drilling system directional drilling of the borehole may be provided by varying factors such as weight-on-bit, the rotation speed, etc. 
     With regards to rotary drilling, known methods of directional drilling include the use of a rotary steerable system (RSS). In an RSS, the drill string is rotated from the surface, and downhole devices cause the drill bit to drill in the desired direction. Rotating the drill string greatly reduces the occurrences of the drill string getting hung up or stuck during drilling. 
     Rotary steerable drilling systems for drilling deviated boreholes into the earth may be generally classified as either “point-the-bit” systems or “push-the-bit” systems. In the point-the-bit system, the axis of rotation of the drill bit is deviated from the local axis of the bottomhole assembly (“BHA”) in the general direction of the new hole. The hole is propagated in accordance with the customary three-point geometry defined by upper and lower stabilizer touch points and the drill bit. The angle of deviation of the drill bit axis coupled with a finite distance between the drill bit and lower stabilizer results in the non-collinear condition required for a curve to be generated. There are many ways in which this may be achieved including a fixed bend at a point in the bottomhole assembly close to the lower stabilizer or a flexure of the drill bit drive shaft distributed between the upper and lower stabilizer. 
     Pointing the bit may comprise using a downhole motor to rotate the drill bit, the motor and drill bit being mounted upon a drill string that includes an angled bend. In such a system, the drill bit may be coupled to the motor by a hinge-type or tilted mechanism/joint, a bent sub or the like, wherein the drill bit may be inclined relative to the motor. When variation of the direction of drilling is required, the rotation of the drill-string may be stopped and the bit may be positioned in the borehole, using the downhole motor, in the required direction and rotation of the drill bit may start the drilling in the desired direction. In such an arrangement, the direction of drilling is dependent upon the angular position of the drill string. 
     In its idealized form, in a pointing the bit system, the drill bit is not required to cut sideways because the bit axis is continually rotated in the direction of the curved hole. Examples of point-the-bit type rotary steerable systems, and how they operate are described in U.S. Patent Application Publication Nos. 2002/0011359; 2001/0052428 and U.S. Pat. Nos. 6,394,193; 6,364,034; 6,244,361; 6,158,529; 6,092,610; and 5,113,953 all herein incorporated by reference. 
     Push the bit systems and methods make use of application of force against the borehole wall to bend the drill-string and/or force the drill bit to drill in a preferred direction. In a push-the-bit rotary steerable system, the requisite non-collinear condition is achieved by causing a mechanism to apply a force or create displacement in a direction that is preferentially orientated with respect to the direction of hole propagation. There are many ways in which this may be achieved, including non-rotating (with respect to the hole), displacement based approaches and eccentric actuators that apply force to the drill bit in the desired steering direction. Again, steering is achieved by creating non co-linearity between the drill bit and at least two other touch points. In its idealized form the drill bit is required to cut sideways in order to generate a curved hole. Examples of push-the-bit type rotary steerable systems, and how they operate are described in U.S. Pat. Nos. 5,265,682; 5,553,678; 5,803,185; 6,089,332; 5,695,015; 5,685,379; 5,706,905; 5,553,679; 5,673,763; 5,520,255; 5,603,385; 5,582,259; 5,778,992; 5,971,085 all herein incorporated by reference. 
     Known forms of RSS are provided with a “counter rotating” mechanism which 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 “geostationary” by those skilled in the art. In this disclosure, no distinction is made between the terms “counter rotating” and “geo-stationary.” 
     A push-the-bit system typically uses either an internal or an external counter-rotation stabilizer. The counter-rotation stabilizer remains at a fixed angle (or geo-stationary) with respect to the borehole wall. When the borehole is to be deviated, an actuator presses a pad against the borehole wall in the opposite direction from the desired deviation. The result is that the drill bit is pushed in the desired direction. 
     The force generated by the actuators/pads is balanced by the force to bend the bottomhole assembly, and the force is reacted through the actuators/pads on the opposite side of the bottomhole assembly and the reaction force acts on the cutters of the drill bit, thus steering the hole. In some situations, the force from the pads/actuators may be large enough to erode the formation where the system is applied. 
     For example, the Schlumberger™ Powerdrive™ system uses three pads arranged around a section of the bottomhole assembly to be synchronously deployed from the bottomhole assembly to push the bit in a direction and steer the borehole being drilled. In the system, the pads are mounted close, in a range of 1-4 ft behind the bit and are powered/actuated by a stream of mud taken from the circulation fluid. In other systems, the weight-on-bit provided by the drilling system or a wedge or the like may be used to orient the drilling system in the borehole. 
     While system and methods for applying a force against the borehole wall and using reaction forces to push the drill bit in a certain direction or displacement of the bit to drill in a desired direction may be used with drilling systems including a rotary drilling system, the systems and methods may have disadvantages. For example such systems and methods may require application of large forces on the borehole wall to bend the drill-string and/or orient the drill bit in the borehole; such forces may be of the order of 5 kN or more, that may require large/complicated downhole motors or the like to be generated. Additionally, many systems and methods may use repeatedly thrusting of pads/actuator outwards into the borehole wall as the bottomhole assembly rotates to generate the reaction forces to push the drill bit, which may require complex/expensive/high maintenance synchronizing systems, complex control systems and/or the like. 
     The drill bit is known to “dance” or clatter around in a borehole in an unpredictable or even random manner. This stochastic movement is generally non-deterministic in that a current state does not fully determine its next state. Point-the-bit and push-the-bit techniques are used to force a drill bit into a particular direction and overcome the tendency for the drill bit to clatter. These techniques ignore the stochastic dance a drill bit is likely to make in the absence of directed force. 
     SUMMARY 
     In an embodiment, the present disclosure provides for steering a direction system to directionally drill a borehole. In one embodiment, steering of the directional drilling system is provided by controlling stochastic motion of a bottomhole assembly, which assembly includes a drill bit, of the directional drilling system in the borehole and/or controlling reactionary forces between the bottomhole assembly and an inner-wall/sidewall of the borehole when a side force is being applied to the bottomhole assembly/drill bit. These steering methods/systems may provide for changing direction of the wellbore system with less effort/less complex machinery/less cost than conventional steering mechanisms. In an embodiment, the direction of drilling of the drilling system is monitored and the monitored direction of drilling is processed along with a desired endpoint of the borehole being drilled. The directional drilling system is then controlled to drill the borehole so as to reach the desired endpoint by adjusting the steering provided by controlling the stochastic motion and/or biasing a side force acting on the bottomhole assembly/drill bit. Any number of biasing mechanisms can be used, such as described, for example, in co-pending U.S. patent application Ser. No. 12/116,408, filed May 7, 2008, on the same date as the present application, entitled “SYSTEM AND METHOD FOR DIRECTIONALLY DRILLING A BOREHOLE WITH A ROTARY DRILLING SYSTEM”, which is incorporated by reference in its entirety for all purposes. Some embodiments can resort to conventional steering mechanisms to supplement or as an alternative to the biasing mechanism. 
     Further areas of applicability of the present disclosure will become apparent from the detailed description provided hereinafter. It should be understood that the detailed description and specific examples, while indicating various embodiments, are intended for purposes of illustration only and are not intended to necessarily limit the scope of the disclosure. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present disclosure is described in conjunction with the appended figures: 
         FIG. 1A  depicts a wellsite system in which the present invention can be employed. 
         FIG. 1B  depicts a block diagram of an embodiment of a drill bit direction system; 
         FIG. 2  illustrates a flowchart of one embodiment of a process for controlling drill bit direction; and 
         FIG. 3  illustrates a state machine for managing the drill bit direction system. 
     
    
    
     In the appended figures, similar components and/or features may have the same reference label. Further, various components of the same type may be distinguished by following the reference label by a dash and a second label that distinguishes among the similar components. If only the first reference label is used in the specification, the description is applicable to any one of the similar components having the same first reference label irrespective of the second reference label. 
     DETAILED DESCRIPTION 
     The ensuing description provides preferred exemplary embodiment(s) only, and is not intended to limit the scope, applicability or configuration of the disclosure. Rather, the ensuing description of the preferred exemplary embodiment(s) will provide those skilled in the art with an enabling description for implementing a preferred exemplary embodiment. It being understood that various changes may be made in the function and arrangement of elements without departing from the spirit and scope as set forth in the appended claims. 
       FIG. 1A  illustrates a wellsite system in which the present invention can be employed. The wellsite can be onshore or offshore. In this exemplary system, a borehole  11  is formed in subsurface formations by rotary drilling in a manner that is well known. Embodiments of the invention can also use directional drilling, as will be described hereinafter. 
     A drill string  12  is suspended within the borehole  11  and has a bottom hole assembly  100  which includes a drill bit  105  at its lower end. The surface system includes platform and derrick assembly  10  positioned over the borehole  11 , the assembly  10  including a rotary table  16 , kelly  17 , hook  18  and rotary swivel  19 . The drill string  12  is rotated by the rotary table  16 , energized by means not shown, which engages the kelly  17  at the upper end of the drill string. The drill string  12  is suspended from a hook  18 , attached to a traveling block (also not shown), through the kelly  17  and a rotary swivel  19  which permits rotation of the drill string relative to the hook. As is well known, a top drive system could alternatively be used. 
     In the example of this embodiment, the surface system further includes drilling fluid or mud  26  stored in a pit  27  formed at the well site. A pump  29  delivers the drilling fluid  26  to the interior of the drill string  12  via a port in the swivel  19 , causing the drilling fluid to flow downwardly through the drill string  12  as indicated by the directional arrow  8 . The drilling fluid exits the drill string  12  via ports in the drill bit  105 , and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the borehole, as indicated by the directional arrows  9 . In this well known manner, the drilling fluid lubricates the drill bit  105  and carries formation cuttings up to the surface as it is returned to the pit  27  for recirculation. 
     The bottom hole assembly  100  of the illustrated embodiment a logging-while-drilling (LWD) module  120 , a measuring-while-drilling (MWD) module  130 , a rotary steerable system and motor, and drill bit  105 . 
     The LWD module  120  is housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, e.g. as represented at  120 A. (References, throughout, to a module at the position of  120  can alternatively mean a module at the position of  120 A as well.) The LWD module includes capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the present embodiment, the LWD module includes a pressure measuring device. 
     The MWD module  130  is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string and drill bit. The MWD tool further includes an apparatus (not shown) for generating electrical power to the downhole system. This may typically include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed. In the present embodiment, the MWD module includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device. 
     A particularly advantageous use of the system hereof is in conjunction with controlled steering or “directional drilling.” In this embodiment, a roto-steerable subsystem  150  ( FIG. 1A ) is provided. 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, for example, advantageous in offshore drilling because it enables many 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 used in vertical drilling operation as well. 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. A known method of directional drilling includes the use of a rotary steerable system (“RSS”). In an RSS, the drill string is rotated from the surface, and downhole devices cause the drill bit to drill in the desired direction. Rotating the drill string greatly reduces the occurrences of the drill string getting hung up or stuck during drilling. 
     Rotary steerable drilling systems for drilling deviated boreholes into the earth may be generally classified as either “point-the-bit” systems or “push-the-bit” systems. In the point-the-bit system, the axis of rotation of the drill bit is deviated from the local axis of the bottom hole assembly in the general direction of the new hole. The hole is propagated in accordance with the customary three point geometry defined by upper and lower stabilizer touch points and the drill bit. The angle of deviation of the drill bit axis coupled with a finite distance between the drill bit and lower stabilizer results in the non-collinear condition required for a curve to be generated. There are many ways in which this may be achieved including a fixed bend at a point in the bottomhole assembly close to the lower stabilizer or a flexure of the drill bit drive shaft distributed between the upper and lower stabilizer. In its idealized form, the drill bit is not required to cut sideways because the bit axis is continually rotated in the direction of the curved hole. Examples of point-the-bit type rotary steerable systems, and how they operate are described in U.S. Patent Application Publication Nos. 2002/0011359; 2001/0052428 and U.S. Pat. Nos. 6,394,193; 6,364,034; 6,244,361; 6,158,529; 6,092,610; and 5,113,953 all herein incorporated by reference. In the push-the-bit rotary steerable system there is usually no specially identified mechanism to deviate the bit axis from the local bottom hole assembly axis; instead, the requisite non-collinear condition is achieved by causing either or both of the upper or lower stabilizers to apply an eccentric force or displacement in a direction that is preferentially orientated with respect to the direction of hole propagation. Again, there are many ways in which this may be achieved, including non-rotating (with respect to the hole) eccentric stabilizers (displacement based approaches) and eccentric actuators that apply force to the drill bit in the desired steering direction. Again, steering is achieved by creating non co-linearity between the drill bit and at least two other touch points. In its idealized form the drill bit is required to cut side ways in order to generate a curved hole. Examples of push-the-bit type rotary steerable systems, and how they operate are described in U.S. Pat. Nos. 5,265,682; 5,553,678; 5,803,185; 6,089,332; 5,695,015; 5,685,379; 5,706,905; 5,553,679; 5,673,763; 5,520,255; 5,603,385; 5,582,259; 5,778,992; 5,971,085 all herein incorporated by reference. 
     Referring first to  FIG. 1B , a block diagram of an embodiment of a drill bit direction system  160  is shown. In certain aspects of the present invention, a surface processor  164  is located above ground to manage the drillstring at the surface. The drillstring may be managed at the surface by changing the rate of rotation of the drillstring, changing the weight-on-bit being provided by the drillstring and/or the like. As such, the surface processor  164  may be in communication with and control a drillstring rotation control  172  and/or a weight-on-bit control  168 . Often, a person is in control of drilling operations and the surface processor  164  may have a display, graphical user interface or the like to provide information/instructions to the driller. 
     The surface processor  164  may manage/guide the direction of drilling in the earth formation by controlling surface and/or downhole devices to change one or more drilling parameters, such as weight-on-bit, speed of rotation, application of side force to the bottomhole assembly and/or the like. In other aspects of the present invention, a downhole controller  184  may manage a direction of drilling. A drilling trajectory may be communicated to the downhole controller  184  and the downhole controller  184  may control drilling parameters to control the direction of drilling. The drilling trajectory may be updated by communications sent to the downhole controller  184  during the drilling process. In some aspects, it may be desirable for the downhole controller  184  to manage the direction of drilling because of difficulties in communicating from a downhole location to the surface. Furthermore, the downhole controller  184  may be closer to and/or better able to communicate with downhole devices for changing drilling parameters, such as side force generators, than the surface processor  164 . In certain aspects of the present invention, the directional drilling system may comprise both the surface processor  164  and/or the downhole controller  184  and the management of direction of drilling may be shared by the surface processor  164  and/or the downhole controller  184 . 
     In an embodiment of the present invention, a bottomhole assembly  180  of the directional drilling system may be coupled with a stochastic steering mechanism  196  and/or a biasing mechanism  192 . The stochastic steering mechanism  196  may be a mechanism that controls the interactions between the bottomhole assembly  180  and/or a drill bit  194  and an inner-wall of the borehole being drilled by the directional drilling system. Interactions may occur between an outer-surface of the bottomhole assembly  180  and/or the drill bit  194  and/or gauge pads (not shown) on the bottomhole assembly  180  and/or the drill bit  194  during the drilling process as a result of stochastic/radial motion of the bottomhole assembly  180  and/or the drill bit  194  in the borehole. The interactions between the bottomhole assembly  180  and/or the drill bit  194  and the inner-wall may comprise impacts between the bottomhole assembly  180  and/or the drill bit  194  and the inner-wall and/or continuous interactions between the bottomhole assembly  180  and/or the drill bit  194  and the inner-wall with instances of increased or decreased interaction forces between the bottomhole assembly  180  and/or the drill bit  194  and the inner-wall, i.e., the bottomhole assembly  180  and/or the drill bit  194  may essentially be in continuous contact with the inner-wall, but radial motion of the bottomhole assembly  180  and/or the drill bit  194  during a drilling process may provide for generating stochastic contact forces between the bottomhole assembly  180  and/or the drill bit  194  and the inner-wall. As provided in U.S. application Ser. No. 11/839,381 filed on Aug. 15, 2007, entitled SYSTEM AND METHOD FOR CONTROLLING A DRILLING SYSTEM FOR DRILLING A BOREHOLE IN AN EARTH FORMATION, the impacts and/or the stochastic contact forces may be controlled, focussed and/or biased to provide for directing the drill bit  194  to directionally drill the borehole. 
     In an embodiment of the present invention, the bottomhole assembly  180  of the directional drilling system may be coupled with a biasing mechanism  192 . The biasing mechanism  192  may comprise a system, such as described in U.S. patent application Ser. No. 12 /116,408, filed on the same date as the present application, entitled “SYSTEM AND METHOD FOR DIRECTIONALLY DRILLING A BOREHOLE WITH A ROTARY DRILLING SYSTEM”, that may provide for biasing/focusing a side force acting on the bottomhole assembly  180  and/or the drill bit  194 . 
     Information may be communicated from the surface processor  164  and/or the downhole controller  184  to the bottomhole assembly  180 , the information may include a desired orientation or direction to achieve for the drill bit  194 , selection of various biasing and steering mechanisms  192 ,  196  to use to achieve drilling in a desired direction, and/or the like. In certain aspects, the direction may be defined relative to any fixed point, such as the earth. The information may additionally provide control information for the bottomhole assembly  180 , the biasing mechanism  192  and/or the stochastic steering mechanism  196 . 
     The bottomhole assembly  180  may comprise the downhole controller  184 , an orientation or direction sensor  188 , a bit rotation sensor  199 , one or more biasing mechanism  192 , and one or more stochastic steering mechanism  196 . A typical bottomhole assembly (“BHA”) may have more control systems, which are not shown in  FIG. 1B . Information may be communicated to the bottomhole assembly  180  from the surface processor  164  and/or the downhole controller  184  to indicate a preferred drilling direction. In certain embodiments of the present invention, the biasing and steering mechanisms  192 ,  196  may be controlled by the surface processor  164  and/or the downhole controller  184  to steer the drilling system. In certain aspects, the downhole controller  164  may provide for controlling real-time operation of the biasing and steering mechanisms  192 ,  196  with information gathered from the direction and bit rotation sensors  188 ,  199 . 
     Merely by way of example, the surface processor  164  and/or the downhole controller  184  may be in communication with drilling sensors, such as sensors measuring weight-on-bit, torque, speed of rotation of the drillstring, bit wear, borehole pressure, borehole temperature and/or the like. Additionally, sensors measuring characteristics of the formation being drilled such as pore pressure, formation-type and or the like may also communicate with the surface processor  164  and/or the downhole controller  184 . The surface processor  164  and/or the downhole controller  184  may process the sensed information and a desired endpoint for the wellbore and control the bottomhole assembly  180  to provide directional drilling of the borehole to achieve the desired endpoint. The desired endpoint may comprise a trajectory that passes through a region of formation containing a hydrocarbon, may be a general endpoint that provides such a trajectory, may be a more specific endpoint designed to arrive at a specific location in the formation, may be a temporary endpoint that may be superseded by a further endpoint after it is achieved and or the like. 
     In certain aspects, a drilling trajectory to achieve a desired directional borehole may be communicated to the surface processor  164  and/or the downhole controller  184  and the surface processor  164  and/or the downhole controller  184  may control the bottomhole assembly  180  to maintain the drilling trajectory. However, this may provide for a meandering borehole, may not take into account preferable drilling conditions outside of the drilling trajectory and may not allow for a time lag that may be inherent in changing the direction of drilling using the and/or the steering mechanisms  192 ,  196 . For example, the stochastic steering mechanism  196  provides for controlling stochastic motion of the drill bit  194  to direct the drilling direction of the drilling system and biasing mechanism  192  provides for biasing/focusing a side force to direct the direction of drilling of the drilling system both of which may involve gradual changes in borehole direction. As such, instead of defined trajectories, the surface processor  164  and/or the downhole controller  184  may process a desired endpoint for the borehole, the drilling measurements, the formation measurements, the present direction of drilling, the rate of effect on changing drilling direction of the biasing and/or the stochastic steering mechanisms  192 ,  196  and/or the like to determine how to control the biasing and/or the stochastic steering mechanisms  192 ,  196  to steer the drilling system to achieve the desired endpoint. In some aspects, a PeriScope™ system, EcoScope™ system, StethoScope™ system and/or the like may be used to determine how to direct the drilling of the borehole. 
     The PeriScope™ system maps bed boundaries and clearly indicates the best steering direction, and the deep measurement range gives you an early warning that steering adjustments are required to avoid water or drilling hazards or to avoid exiting the reservoir target. The EcoScope™ system may act as a logging while drilling tool that may use resistivity, neutron porosity, and azimuthal gamma ray and density to evaluate a formation and its properties during the drilling process. Drilling optimization measurements may include Annular Pressure While Drilling, caliper borehole measurement, and shock. The StethoScope™ system may improve geosteering and geostopping decisions with real-time formation pressure measurements. Quick decisions may be based on results from the StethoScope™ system to eliminate time wasted drilling pressure-depleted formations and can preserve virgin pressure zones scheduled for sidetrack development or completion. 
     Measurement-While-Drilling (MWD) surveying for directional and horizontal drilling processes is performed to provide the orientation and the position of the BHA [Conti, 1999]. Azimuth, the inclination and the tool face angles determine the orientation of the BHA, while latitude, longitude and altitude determine the position of the BHA. The altitude directly determines the true vertical depth of the BHA. State of the art MWD surveying techniques are based on magnetic surveying which incorporates three-axis magnetometers and three-axis accelerometers arranged in three-mutually orthogonal directions. The three-axis accelerometers monitor the Earth gravity field to provide the inclination and the tool face angles. This information is combined with the magnetometer measurements of the Earth magnetic field to provide the azimuth. 
     For this purpose, two different approaches are currently used, on the one hand rotary steering systems wherein the rotation of the drill bit is deflected into the desired direction while the entire drill string is rotated from surface, or mud motors in combination with bent subs or housings, wherein only the lower end of the drill string is rotated by the action of the mud motor. The surveying system can include a measurement-while-drilling (MWD) system and/or a logging-while drilling (LWD) system for determining orientation parameters in the course of the drilling operation and/or measuring parameters of the formation or in the borehole. Moreover, in certain aspects, especially in shallow horizontal-type wells, the bottomhole assembly and/or the drill bit may be fitted with a beacon or the like emitting electromagnetic radiation or vibrations that may pass through the earth formation being drilled and a receiver(s) may be used at the surface to receive the transmitted signals and provide for determining the location of the bottomhole assembly and or the direction of drilling. 
     Drilling data, which may include direction data, steering/biasing data, logging-while-drilling data, forward looking boundary identification data and/or the like, may be communicated to the downhole controller  184  and/or from the BHA  180  back to the surface processor  164  at the surface. The direction of the drill bit may be periodically communicated to the surface processor  164  along with data regarding the use of various biasing and steering mechanisms  192 ,  196 . A borehole path information database  176  may store the information gathered downhole to know how the borehole navigates through the formation. The borehole path information database  176  may be located at surface or downhole. The surface processor  164  and/or the downhole controller  184  may recalculate the best orientation or direction to use for the drill bit  194  and communicate that to the BHA  180  to override any prior instructions. Additionally, the effectiveness of the various biasing and steering mechanisms  192 ,  196  can be analyzed with other information gathered on the formation to provide guidance downhole on how to best use the available biasing and steering mechanisms  192 ,  196  to achieve the geometry of the borehole desired for a particular drill site. 
     Merely by way of example, my monitoring changes in the formation being drilled, boundary conditions, drilling properties and/or the like, settings for the biasing and/or the stochastic steering mechanisms  192 ,  196  may be determined to provide for steering the drilling system to drill the borehole to reach a desired endpoint. As previously noted, while the biasing and/or the stochastic steering mechanisms  192 ,  196  of the present invention may require less downhole equipment, less complicated downhole equipment, less downhole force generation and/or the like, the systems may require a temporal lag to provide the desired steering of the drilling system and the surface processor  164  and/or the downhole controller  184  may calculate this temporal lag into the processing of the setting for the biasing and/or the stochastic steering mechanisms  192 ,  196  and/or the trajectory to reach the desired endpoint. Further, logging-while-drilling measurements may alter the desired endpoint and this change may be processed into the steering of the drilling system by the biasing and/or the stochastic steering mechanisms  192 ,  196 . 
     The direction sensor  188  can determine the current direction of the drill bit  194  and/or the bottomhole assembly  180  with respect to a particular frame of reference in three dimensions (i.e., relative to the earth or some other fixed point). Various techniques can be used to determine the current direction, for example, an inertially- or roll-stabilized platform with gyros can be compared to references on the drill bit  194 , accelerometers may be used to track direction and/or magnetometers may measure direction relative to the earth&#39;s magnetic field. Measurements may be noisy and a filter may be used to average out the noise from measurements. In other aspects of the present invention, a microseismic system may be used to track location of the drill bit  194  and/or the bottomhole assembly  180  by measuring vibrational data in the earth formation. 
     The bit rotation sensor  199  allows monitoring of the phase of rotation for the drill bit  194 . The downhole controller  184  may use the sensor information to allow for synchronized control of the biasing and/or the stochastic steering mechanisms  192 ,  196 . With knowledge of the phase, the biasing and/or the stochastic steering may be performed every rotation cycle or any integer fraction of the cycles (e.g., every other rotation, every third rotation, every fourth rotation, every tenth rotation, etc.). Other embodiments do not use a bit rotation sensor  199  or synchronized manipulation of the biasing mechanism(s)  192 . 
     There are various stochastic steering mechanisms  196  that persistently enforce drill bit movement. The stochastic steering mechanism  196  intentionally takes advantage of the stochastic movement of the drill bit  194  that naturally occurs. A given site may use one or more of these stochastic steering mechanism  196  to create a borehole that changes direction as desired through the formation. Other embodiments may forgo stochastic steering mechanism  196  completely by reliance on biasing mechanisms  192  for directional drilling. 
     The downhole controller  184  may use the information sent from the surface processor  164  along with the direction and bit rotation sensors  188 ,  199  to actively manage the use of biasing and steering mechanisms  192 ,  196 . The desired direction of the drill bit along with guidelines for using various biasing and steering mechanisms  192 ,  196  may be communicated from the surface processor  164 . The downhole controller  184  may use fuzzy logic, neural algorithms, expert system algorithms to decide how and when to influence the drill bit direction in various embodiments. Generally, the speed of communication between the BHA  180  and the surface processor  164  does not allow real-time control from the surface in this embodiment, but other embodiments could allow for surface control in real-time. The stochastic direction of the drill bit can be adaptively used in a less rigid manner. For example, if a future turn in the borehole is desired and the drill bit is making the turn prematurely, the turn can be accepted and the future plan revised. 
     With reference to  FIG. 2 , a flowchart of an embodiment of a process  200 - 1  for controlling drill bit direction is shown. This embodiment uses a biasing and/or stochastic steering mechanism to control the direction of the drill bit. The depicted portion of the process beings in block  204  where an analysis of the formation and an end point is performed to plan the borehole geometry. The surface processor manipulates the drillstring, drawworks and other systems in block  208  to create the borehole according to the plan. A desired direction of the drill bit is determined in block  212  and communicates to the downhole controller in block  216 . The desired direction could be a single goal or a range of acceptable directions. 
     The desired direction along with any biasing selection criteria is received by the downhole controller in block  220 . The current pointing of the drill bit is determined by the direction sensor in block  224 . It is determined in block  228  if the direction is acceptable based upon the instructions from the surface processor. This embodiment allows some flexibility in the direction and re-determines the plan based upon the movement of the drill bit and the effectiveness of the biasing and/or stochastic steering mechanism. An acceptable direction is one that allows achieving the end point with the drill bit if the plan were revised. A certain plan may have predetermined deviations or ranges of direction that are acceptable, but still avoid parts of the formation that are not desired to pass through. 
     Where the direction is not acceptable, processing goes from block  228  to block  236  where the biasing and/or stochastic steering mechanism is activated. The biasing and/or stochastic steering mechanism could be activated once or for a period of time. Alternatively, the biasing and/or stochastic steering mechanism could be activated periodically in synchronization with the rotation of the drill bit. The biasing and/or stochastic steering mechanism selects or emphasizes those components of the radial motion of the drill bit or a side force acting on the drill bit that occur in the desired direction(s). 
     Where the direction is acceptable as determined in block  228 , processing continues to block  240 . In certain aspects, the biasing and/or stochastic steering mechanism  236  may achieve directional control by holding the direction of drilling in the desired direction(s). Where un-needed because the erratic motion of the drill bit is already in the desired direction(s), the stochastic steering mechanism may not be activated. Similarly, where a side force acting on the drill bit, such as a side force generated by a push the bit system, is already in the desired direction the biasing mechanism may not be activated. In block  240 , the current direction is communicated by the downhole controller to the surface processor. Communication may be via regular telemetry methods or via wired drill pipe or the like. After reporting, processing loops back to block  212  for further management of the direction based upon any new instruction from the surface. 
     Referring next to  FIG. 3 , an embodiment of a state machine  300 - 1  for managing the drill bit direction system  100  is shown. This control system moves between two states based upon a determination in state  304  if the drill bit is not in alignment with a desired direction or range of directions. This embodiment corresponds to the embodiment of  FIG. 2 . Where there is disorientation beyond an acceptable deviation, the drill bit direction system goes from state  304  to state  308 . In state  308 , one or more of the biasing mechanism and/or steering mechanisms are tried. In some cases, the same biasing and/or stochastic steering mechanism may be tried with different parameters. For example, a gage pad can be moved at one phase in the bit rotation cycle, but later another phase is tried with the same or a different movement of the gage pad. 
     A number of variations and modifications of the disclosed embodiments can also be used. For example, the invention can be used on drilling boreholes or cores. The control of the biasing process is split between the ICIS and the BHA in the above embodiments. In other embodiments, all of the control can be in either location. 
     Specific details are given in the above description to provide a thorough understanding of the embodiments. However, it is understood that the embodiments may be practiced without these specific details. For example, circuits may be shown in block diagrams in order not to obscure the embodiments in unnecessary detail. In other instances, well-known circuits, processes, algorithms, structures, and techniques may be shown without unnecessary detail in order to avoid obscuring the embodiments. 
     Implementation of the techniques, blocks, steps and means described above may be done in various ways. For example, these techniques, blocks, steps and means may be implemented in hardware, software, or a combination thereof. For a hardware implementation, the processing units may be implemented within one or more application specific integrated circuits (ASICs), digital signal processors (DSPs), digital signal processing devices (DSPDs), programmable logic devices (PLDs), field programmable gate arrays (FPGAs), processors, controllers, micro-controllers, microprocessors, other electronic units designed to perform the functions described above, and/or a combination thereof. 
     Also, it is noted that the embodiments may be described as a process which is depicted as a flowchart, a flow diagram, a data flow diagram, a structure diagram, or a block diagram. Although a flowchart may describe the operations as a sequential process, many of the operations can be performed in parallel or concurrently. In addition, the order of the operations may be re-arranged. A process is terminated when its operations are completed, but could have additional steps not included in the figure. A process may correspond to a method, a function, a procedure, a subroutine, a subprogram, etc. When a process corresponds to a function, its termination corresponds to a return of the function to the calling function or the main function. 
     Furthermore, embodiments may be implemented by hardware, software, scripting languages, firmware, middleware, microcode, hardware description languages, and/or any combination thereof. When implemented in software, firmware, middleware, scripting language, and/or microcode, the program code or code segments to perform the necessary tasks may be stored in a machine readable medium such as a storage medium. A code segment or machine-executable instruction may represent a procedure, a function, a subprogram, a program, a routine, a subroutine, a module, a software package, a script, a class, or any combination of instructions, data structures, and/or program statements. A code segment may be coupled to another code segment or a hardware circuit by passing and/or receiving information, data, arguments, parameters, and/or memory contents. Information, arguments, parameters, data, etc. may be passed, forwarded, or transmitted via any suitable means including memory sharing, message passing, token passing, network transmission, etc. 
     For a firmware and/or software implementation, the methodologies may be implemented with modules (e.g., procedures, functions, and so on) that perform the functions described herein. Any machine-readable medium tangibly embodying instructions may be used in implementing the methodologies described herein. For example, software codes may be stored in a memory. Memory may be implemented within the processor or external to the processor. As used herein the term “memory” refers to any type of long term, short term, volatile, nonvolatile, or other storage medium and is not to be limited to any particular type of memory or number of memories, or type of media upon which memory is stored. 
     Moreover, as disclosed herein, the term “storage medium” may represent one or more memories for storing data, including read only memory (ROM), random access memory (RAM), magnetic RAM, core memory, magnetic disk storage mediums, optical storage mediums, flash memory devices and/or other machine readable mediums for storing information. The term “machine-readable medium” includes, but is not limited to portable or fixed storage devices, optical storage devices, wireless channels, and/or various other storage mediums capable of storing that contain or carry instruction(s) and/or data. 
     While the principles of the disclosure have been described above in connection with specific apparatuses and methods, it is to be clearly understood that this description is made only by way of example and not as limitation on the scope of the disclosure.