Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B7/00—Special methods or apparatus for drilling
  • E21B7/04—Directional drilling
  • E21B7/06—Deflecting the direction of boreholes
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
  • E21B44/005—Below-ground automatic control systems

Definitions

• This disclosure relates in general to drilling a borehole and, but not by way of limitation, to controlling direction of drilling for the borehole.
• a borehole may be drilled so as to intercept a particular subterranean-formation at a particular location.
• a drilling trajectory through the earth formation may be pre-planned and the drilling system may be controlled to conform to the trajectory.
• 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.
• 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.
• 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.
• 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.
• RSS rotary steerable system
• 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.
• 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.
• BHA bottomhole assembly
• 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.
• 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.
• 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.
• 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.
• the direction of drilling is dependent upon the angular position of the drill string.
• 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.
• 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.
• 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.
• steering is achieved by creating non co-linearity between the drill bit and at least two other touch points.
• Known forms of RSS are provided with a "counter rotating" mechanism which rotates in the opposite direction of the drill string rotation.
• 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.
• 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.
• the force from the pads/actuators may be large enough to erode the formation where the system is applied.
• the SchlumbergerTM PowerdriveTM 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.
• 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.
• 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.
• 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.
• 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.
• the present disclosure provides for steering a direction system to directionally drill a borehole.
• 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.
• 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 Serial No. / , , filed on the same date as the present application, entitled "SYSTEM AND METHOD FOR DIRECTIONALLY DRILLING A BOREHOLE WITH A ROTARY DRILLING SYSTEM” (temporarily referenced by Attorney Docket No. 57.0834 U.S. CIP), 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.
• FIG. IA depicts a wellsite system in which the present invention can be employed.
• FIG. IB 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
• FIG. 3 illustrates a state machine for managing the drill bit direction system.
• FIG. IA illustrates a wellsite system in which the present invention can be employed.
• the wellsite can be onshore or offshore.
• a borehole 1 1 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.
• a top drive system could alternatively be used.
• 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.
• 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.
• LWD logging- while- drilling
• MWD measuring- while-drilling
• 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 120A. (References, throughout, to a module at the position of 120 can alternatively mean a module at the position of 120A 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.
• 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.
• Directional drilling is the intentional deviation of the wellbore from the path it would naturally take.
• 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.
• 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").
• RSS rotary steerable system
• 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.
• 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.
• 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.
• 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.
• steering is achieved by creating non co-linearity between the drill bit and at least two other touch points.
• FIG. IB a block diagram of an embodiment of a drill bit direction system 160 is shown.
• 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.
• the surface processor 164 may be in communication with and control a drillstring rotation control 172 and/or a weight-on-bit control 168.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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 Serial No.
• 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.
• 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. IB.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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
• 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.
• 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.
• 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.
• 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.
• 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.
• a PeriScopeTM system, EcoScopeTM system, StethoScopeTM system and/or the like may be used to determine how to direct the drilling of the borehole.
• the PeriScopeTM 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 EcoScopeTM 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 StethoScopeTM system may improve geosteering and geostopping decisions with real-time formation pressure measurements.
• 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.
• 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.
• 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.
• MWD measurement-while-drilling
• LWD logging-while drilling
• 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. [0050] 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.
• 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.
• 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's magnetic field. Measurements may be noisy and a filter may be used to average out the noise from measurements.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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.
• 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).
• biasing and/or stochastic steering mechanism 236 may achieve directional control by holding the direction of drilling in the desired direction(s).
• the stochastic steering mechanism may not be activated.
• a side force acting on the drill bit such as a side force generated by a push the bit system
• the biasing mechanism may not be activated.
• 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.
• 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.
• the drill bit direction system goes from state 304 to state 308.
• state 308 one or more of the biasing mechanism and/or steering mechanisms are tried.
• 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.
• 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.
• 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.
• 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.
• ASICs application specific integrated circuits
• DSPs digital signal processors
• DSPDs digital signal processing devices
• PLDs programmable logic devices
• FPGAs field programmable gate arrays
• processors controllers, micro-controllers, microprocessors, other electronic units designed to perform the functions described above, and/or a combination thereof.
• 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.
• embodiments may be implemented by hardware, software, scripting languages, firmware, middleware, microcode, hardware description languages, and/or any combination thereof.
• 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.
• modules e.g., procedures, functions, and so on
• Any machine-readable medium tangibly embodying instructions may be used in implementing the methodologies described herein.
• software codes may be stored in a memory.
• Memory may be implemented within the processor or external to the processor.
• 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.
• 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.
• ROM read only memory
• RAM random access memory
• magnetic RAM magnetic RAM
• core memory magnetic disk storage mediums
• optical storage mediums flash memory devices and/or other machine readable mediums for storing information.
• 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.

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