Patent Publication Number: US-2012024606-A1

Title: System and method for direction drilling

Description:
BACKGROUND 
     The present disclosure generally relates to a system and a method for directional drilling. More specifically, the present disclosure relates to a system and a method which may estimate a position and an orientation of the drill bit during directional drilling. 
     To obtain hydrocarbons, a drill bit is driven into the ground surface to create a wellbore through which the hydrocarbons are extracted. Typically, a drill string is suspended within the wellbore, and the drill bit is located at a lower end of sections of drill pipe which form the drill string. The drill string extends from the surface to the drill bit. The drill string has a bottom hole assembly (“BHA”) located proximate to the drill bit. 
     Directional drilling is the steering of the drill bit so that the drill string travels in a desired direction. Before drilling begins, a well plan is established which indicates a target location and a drilling path to the target location. After drilling commences, the drill string is directed from a vertical drilling path in any number of directions to follow the well plan. Directional drilling may direct the wellbore toward the target location. 
     Further, directional drilling may form deviated branch wellbores from a primary wellbore. For example, directional drilling is useful in a marine environment where a single offshore production platform may reach several hydrocarbon reservoirs by utilizing deviated wells that may extend in any direction from the drilling platform. In addition, directional drilling may control the direction of the wellbore to avoid obstacles, such as, for example, formations with adverse drilling properties. Directional drilling may also enable horizontal drilling through a reservoir. 
     Moreover, directional drilling may correct deviation from the drilling path established by the well plan. Typically, the trajectory of the drill bit deviates from the trajectory established by the well plan because of unpredicted characteristics of the formations being penetrated and/or the varying forces that the drill bit and the drill string experience. When such deviation occurs and is detected, directional drilling may move the drill bit back to the drilling path established by the well plan. 
     Known methods of directional drilling use a mud motor system or a rotary steerable system (“RSS”). For a RSS, the drill string is rotated from the surface, and downhole devices cause the drill bit to drill in the desired direction. A RSS is typically more expensive to operate than a mud motor system. For a mud motor system, the drill pipe is held rotationally stationary during a portion of the drilling operation while the mud motor rotates the drill bit. This operation mode is known as “sliding.” Directional drilling using a mud motor system requires accurate orientation of a bent segment of the mud motor before beginning a “sliding” phase of operation. Rotating the drill string drills the wellbore forward without an angle relative to the previous section of the wellbore, and this operation mode is known as “rotating.” Alternating between sliding and rotating may enable the wellbore to have a desired curvature. 
     The toolface of the BHA is an angular measurement of the orientation of the BHA relative to the top of the wellbore, known as gravity tool face, or relative to magnetic north, known as magnetic tool face. Rotating the drill string changes the orientation of the toolface of the bent segment in the BHA. To effectively steer the drill bit, the operator or the automated system controlling the directional drilling must determine the current location and position of the drill bit and the toolface orientation. Thereafter, if the drilling direction requires adjustment, the operator or the automated system must rotate the drill string to align the toolface of the bent segment with the desired direction. For example, initiating a sliding phase after a rotating phase requires rotation of the drill string to obtain the proper toolface orientation for the bent segment so that the directional drilling during the subsequent sliding phase provides the intended direction of drilling relative to the previous section of the wellbore. 
     Data measured at the surface and/or measured downhole is used to determine the current location and position of the drill bit and the toolface orientation. For example, the current location and position of the BHA are determined using measurements of the inclination and the azimuth of the BHA, known as “D&amp;I” measurements. A measurement-while-drilling (MWD) tool located in the upper end of the BHA obtains the D&amp;I measurements. The MWD tool may have an accelerometer and a magnetometer to measure the inclination and azimuth, respectively. The toolface orientation is determined using a toolface sensor which may be connected to the mud motor, and the toolface sensor may use an accelerometer and/or a gyroscope. The toolface sensor is typically closer to the drill bit than the MWD tool. 
     The D&amp;I measurements are obtained by static surveys made at various time or depth intervals. The operator or the automated system uses the estimated location and the estimated position to control the directional drilling. Accordingly, an accurate estimated location and an accurate estimated position are critical for directional drilling. For example, D&amp;I measurements are typically obtained at a distance from the drill bit, such as, for example, tens of feet. The D&amp;I measurements at this distance from the BHA may not be indicative of the actual D&amp;I at the drill bit, and, accordingly, the estimated location and/or the estimated position of the drill bit may be inaccurate. The directional drilling may be compromised because of the inaccurate estimated location of the drill bit. Accordingly, D&amp;I measurements estimated for locations closer to the drill bit may improve the accuracy of directional drilling. 
     In addition, moving the drill bit to the drilling path established by the well plan may be difficult after deviation from the drilling path. Accordingly, accurately determining how to direct the drill bit to the course established by the well plan may make directional drilling more consistent and predictable relative to currently known systems. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  illustrates a system for directional drilling according to one or more aspects of the present disclosure. 
         FIG. 2  illustrates a method for directional drilling according to one or more aspects of the present disclosure. 
         FIG. 3  illustrates a display of directional drilling data determined according to one or more aspects of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION OF THE PRESENTLY PREFERRED EMBODIMENTS 
     The present disclosure generally relates to a system and a method for directional drilling. More specifically, the present disclosure relates to a system and a method which may estimate a position and an orientation of the drill bit during directional drilling and/or may determine intervals of sliding and rotating to conform the directional drilling to a well plan. 
     Referring now to the drawings wherein like numerals refer to like parts,  FIG. 1  generally illustrates a directional drilling system  10  (hereinafter “the system  10 ”). A drilling operation may be conducted at a wellsite  100  using the directional drilling system. The wellsite  100  may have a wellbore  106  formed by drilling and/or penetrating one or more subsurface formations. 
     The system  10  may have a terminal  104 . The terminal  104  may be, for example, a desktop computer, a laptop computer, a mobile cellular telephone, a personal digital assistant (“PDA”), a 4G mobile device, a 3G mobile device, a 2.5G mobile device, a satellite radio receiver and/or the like. The terminal  104  preferably has a processor for processing data received by the terminal  104 . The terminal  104  may be located at the surface and/or may be remote relative to the wellsite  100 . In an embodiment, the terminal  104  may be located in the wellbore  106 . The present disclosure is not limited to a specific embodiment or a specific location of the terminal  104 , and the terminal  104  may be any device that may be used in the system  10 . Any number of terminals may be used to implement the system  10 , and the present disclosure is not limited to a specific number of terminals. 
     The system  10  may have a drill string  108  suspended within the wellbore  106 , and a drill bit  110  may be located at the lower end of the drill string  108 . The drill string  108  and the walls of the wellbore  106  may form an annulus  107 . The system  10  may have a land-based platform and derrick assembly  112  positioned over the wellbore  106 . The assembly  112  may have a hook  116 , and/or a top drive  118  may be suspended from the hook  116 . The top drive  118  may have one or more motors (not shown) and/or may rotate the drill string  108 . The assembly  112  may have drawworks  114  to raise, suspend and/or lower the drill string  108 . During drilling, the drawworks  114  may be operated to hold the drill string  108  and to control and/or maintain a selected axial force as weight-on-bit (“WOB”) to the drill bit  110 . More specifically, a portion of the weight of the drill string  108  is suspended by the drawworks  114 , and an unsuspended portion of the weight of drill string  108  is transferred to the drill bit  110  as the WOB. The drawworks  114  may have an encoder (not shown in the drawings) which may be configured to determine the depths of points along the drill string  108 . The terminal  104  may be communicatively connected to the encoder to generate a log of depth of the drill bit  110  as a function of time. 
     Drilling fluid  120  may be stored in a reservoir  122  formed at the wellsite  100 . A pump  134  may deliver the drilling fluid  120  to the interior of the drill string  108  to induce the drilling fluid  120  to flow downward through the drill string  108 . A mud motor  111  may use the flow of the drilling fluid  120  to generate electrical power. The drilling fluid  120  may exit the drill string  108  through ports or nozzles (not shown) in the drill bit  110  and then may circulate upward through the annulus  107 . Thus, the drilling fluid  120  may lubricate the drill bit  110  and may carry formation cuttings up to the surface as the drilling fluid  120  returns to the reservoir  122  for recirculation. 
     Sensors  150  at various locations at the wellsite  100  may collect data, preferably in real-time, concerning the operation and the conditions of the wellsite  100 . The sensors  150  may have image generation capabilities. For example, one or more of the sensors  150  may be sensors which may provide information about surface conditions, such as, for example, standpipe pressure, hookload, depth, surface torque, rotary rpm and/or the like. One or more of the sensors  150  may be downhole sensors and/or may be disposed within the wellbore  106  to provide information about downhole conditions, such as, for example, wellbore pressure, weight-on-bit, torque-on-bit, direction, inclination, collar rpm, tool temperature, annular temperature, toolface, along-string measurements and/or the like. The information obtained by the sensors  150  may be transmitted to various components of the system  10 , such as, for example, the terminal  104 . 
     The drill string  108  may have a BHA  130  proximate to the drill bit  110 . The drill bit  110  may be connected to a bent sub  109  which may be angled relative to the BHA  130 . In an embodiment, the bent sub  109  may be angled approximately two degrees or less relative to the BHA  130 . In an embodiment, the mud motor  111  may be connected to the bent sub  109  and/or may rotate the bent sub  109  and/or the drill bit  110  without rotation of the drill string  108 . The mud motor  111  and/or the bent sub  109  may be connected to a mechanical transmission  112 . The mechanical transmission  112  may prevent rotation of the bent sub  109  relative to the remainder of the drill string  108  if the drill string  108  is rotating. The mechanical transmission  112  may enable the mud motor  111  to rotate the bent sub  109  if the drill string  108  is sliding. Within the bent sub, may be a drive shaft attached to the mud motor  111  and the drill bit  110 . 
     The BHA  130  may have one or more tools for measuring, processing and/or storing information and/or communicating with the terminal  104 . Additionally, the BHA  130  may have mud motors, rotary steerable assemblies and/or reamers which may divert a portion of the drilling fluid  120  to the annulus. 
     For example, the BHA  130  may have a logging-while-drilling (LWD) module  160 . The LWD module  160  may be housed in a drill collar of the BHA  130  and may have one or more known types of logging tools. The LWD module  160  may have capabilities for measuring and processing data acquired from and/or through the wellbore  106 . In addition, the LWD module  160  may measure properties of the one or more subsurface formations adjacent to the wellbore  106 . 
     The BHA  130  may have a measuring-while-drilling (MWD) module  170 . The MWD module  170  may be housed in a drill collar located at the upper end of the BHA  130  and may have one or more devices for measuring characteristics of the drill string  108  and the drill bit  110 . For example, the MWD module  170  may measure physical properties, such as, for example, pressure, temperature and/or wellbore trajectory. The MWD module  170  may have a D&amp;I sensor  172  which may determine the inclination and the azimuth of the BHA  130 . For example, the D&amp;I sensor  172  may use an accelerometer and/or a magnetometer to determine the inclination and the azimuth of the BHA  130 . The D&amp;I sensor  172  may use any means for determining the inclination and the azimuth of the BHA  130  known to one having ordinary skill in the art. 
     The BHA  130  may have a toolface sensor  180  which determines the toolface orientation of the BHA  130 . The toolface sensor  180  may use one or more magnetometers and/or one or more accelerometers to determine the azimuthal orientation of the BHA  130  relative to the earth&#39;s magnetic north and/or may use one or more gravitation sensors to determine the azimuthal orientation of the BHA  130  relative to the earth&#39;s gravity vector. The toolface sensor  180  may use any means for determining the toolface orientation of the BHA  130  known to one having ordinary skill in the art. 
     The MWD module  170  may have a mud flow telemetry device  176  which may selectively block passage of the drilling fluid  20  through the drill string  108 . The mud flow telemetry device  176  may transmit data from the BHA  130  to the surface by modulation of the pressure in the drilling fluid  20 . Modulated changes in pressure may be detected by a pressure sensor  180  communicatively connected to the terminal  104 . The terminal  104  may interpret the modulated changes in pressure to reconstruct the data sent from the BHA  130 . For example, the mud flow telemetry device  176  may transmit the inclination, the azimuth and the toolface orientation to the surface by modulation of the pressure in the drilling fluid  20 , and the terminal  104  may interpret the modulated changes in pressure to obtain the inclination, the azimuth and the toolface orientation of the BHA  130 . The mud pulse telemetry may be implemented using a system such as that described in U.S. Pat. No. 5,517,464 assigned to the assignee of the present disclosure and incorporated by reference in its entirety. Alternatively, wired drill pipe, electromagnetic telemetry and/or acoustic telemetry may be used instead of or in addition to mud pulse telemetry. For example, mud pulse telemetry may be used in conjunction with or as backup for wired drill pipe as described hereafter. 
     Wired drill pipe may communicate signals along electrical conductors in the wired drill pipe. Wired drill pipe joints may be interconnected to form the drill string  108 . The wired drill pipe may provide a signal communication conduit communicatively coupled at each end of each of the wired drill pipe joints. For example, the wired drill pipe preferably has an electrical and/or optical conductor extending at least partially within the drill pipe with inductive couplers positioned at the ends of each of the wired drill pipe joints. The wired drill pipe may enable communication of the data from the BHA  130  to the terminal  104 . Examples of wired drill pipe that may be used in the present disclosure are described in detail in U.S. Pat. Nos. 6,641,434 and 6,866,306 to Boyle et al. and U.S. Pat. No. 7,413,021 to Madhavan et al. and U.S. Patent App. Pub. No. 2009/0166087 to Braden et al., assigned to the assignee of the present application and incorporated by reference in their entireties. The present disclosure is not limited to a specific embodiment of the telemetry system. The telemetry system may be any system capable of transmitting the data from the BHA  130  to the terminal  104  as known to one having ordinary skill in the art. 
     The wellbore  106  may be drilled according to a well plan established prior to drilling. The well plan typically sets forth equipment, pressures, trajectories and/or other parameters that define the drilling process for the wellsite  100 . The well plan may establish a target location, such as, for example, a location within or adjacent to a reservoir of hydrocarbons, and/or may establish a drilling path by which the drill bit  110  may travel to the target location. The drilling operation may be performed according to the well plan. However, as the information is obtained, the drilling operation may need to deviate from the well plan. For example, as drilling or other operations are performed, the subsurface conditions may change, and the drilling operation may require adjustment. 
       FIG. 2  generally illustrates a method  200  for directional drilling. Computer readable medium, such as, for example, a compact disc, a DVD, a computer memory, a hard drive and/or the like, may enable the terminal  104  to perform the method  300  and/or be used in the system  10 . In step  210 , the terminal  104  may use measurements of the inclination, the azimuth and/or the toolface orientation of the BHA  130  to calibrate a forward model of drilling behavior of the BHA  130 . The toolface sensor  180  may measure the toolface orientation of the BHA  130  at a plurality of times, and/or the D&amp;I sensor  172  may measure the inclination and the azimuth of the BHA  130  at a plurality of times. Moreover, the sensors  150  may provide additional measurements obtained at a plurality of times, such as, for example, a depth, a rate of penetration, a pressure differential across the mud motor  111 , and/or the like. 
     The D&amp;I sensor  172 , the toolface sensor  180  and/or the sensors  150  may transmit the measurements of the inclination and the azimuth, the measurements of the toolface orientation and/or the additional measurements (collectively hereinafter “the measurements”), respectively, to the terminal  104 . For example, the D&amp;I sensor  172 , the toolface sensor  180  and/or the sensors  150  may transmit the measurements using the mud flow telemetry device  176 . The measurements may be transmitted to the terminal  104  using any means known to one having ordinary skill in the art. 
     As generally shown in  FIG. 3 , the terminal  104  may use the measurements of the toolface orientation obtained at a plurality of times to generate a plot  280  of the toolface orientation as a function of depth. The terminal  104  may use the measurements of the inclination and the azimuth obtained at a plurality of times to generate a plot  290  of D&amp;I measurements as a function of depth. The terminal  104  may have a log of depth as a function of time and may use the measurements with the log to generate the plot  280  and/or the plot  290 . For example, the log of depth as a function of time may be based on the additional measurements and/or data obtained at the surface, such as, for example, data obtained by the encoder of the drawworks  114 . Moreover, in an embodiment, the terminal  104  may use the additional measurements to generate a plot of rate of penetration as a function of depth (not shown) and/or a plot of pressure differential across the mud motor  111  as a function of depth (not shown). 
     The terminal  104  may use the plot  290  of the D&amp;I measurements to interpolate a curve connecting the D&amp;I data points using any interpolation method known to one having ordinary skill in the art. For example, an algorithm, such as a linear regression algorithm, may be used to interpolate the curve connecting the D&amp;I data points. In an embodiment, the curve may be a polynomial curve. The system  10  and the method  200  are not limited to a specific embodiment of the curve or a specific method of interpolating the curve, and the system  10  and the method  200  may use any mathematical function suitable for modeling the drilling behavior of the BHA  130 . 
     The input for calibrating the model may be data regarding the wellbore  106  and/or other wellbores which have previously been drilled. For example, the model may be based on data regarding other wellbores which were drilled with a similar BHA  130  and/or a similar drill bit  110 . In an embodiment, drilling of the wellbore  106  may be initiated using a model of the drilling behavior of the BHA  130  generated from data from other wellbores. 
     Further, the input for the model may be drilling parameters associated with the measurements. For example, one or more of the parameters may be the measurements of the inclination, the azimuth and/or the toolface orientation. As a further example, one of the parameters may be the WOB because the toolface orientation may variate more at a higher WOB relative to a lower WOB. As a further example, one or more of the parameters may be properties of the subsurface formation through which the BHA  130  is drilling, the geometry of the BHA  130 , the flow rate of the drilling fluid  20 , the rotation speed of the drill string  108 , operation mode of the drill string  108  as sliding or rotating, the rotation speed of the drill bit  110 , and/or the like. Accordingly, the terminal  104  may use the additional measurements to calibrate the forward model of drilling behavior of the BHA  130 . 
     As the wellbore  106  is drilled to greater depths, more data is acquired. The measurements may be periodically obtained, and the increase in the amount of data may improve the accuracy of the forward model of the drilling behavior of the BHA  130 . For example, the inclination, the azimuth, the toolface orientation, the rate of penetration and/or the pressure differential across the mud motor  111  may be periodically determined, and the forward model of the drilling behavior of the BHA  130  may be adjusted to account for the newly obtained measurements. Accordingly, the model may be periodically calibrated using data acquired downhole. 
     During periodic calibration of the forward model of the drilling behavior of the BHA  130 , the terminal  104  may compare measurements of the inclination and/or the azimuth to values previously estimated from the model. Then, the terminal  104  may adjust the model to minimize any difference between the measurements and the estimated values. Calibration may use a least squares method, a least mean squares method, curve fitting and/or the like; however, any mathematical optimization technique for fitting a mathematical function to a data set may be used. 
     For example, the terminal  104  may estimate values for the inclination, the azimuth and/or the toolface orientation for one or more selected depths before the D&amp;I sensor  172  and/or the toolface sensor  180 , respectively, reach the one or more selected depths. Then, after the D&amp;I sensor  172  and/or the toolface sensor  180  reach the one or more selected depths, the terminal  104  may compare the measurements obtained at the selected depth to the value estimated for the selected depth. Then, the terminal  104  may adjust the forward model of the drilling behavior of the BHA  130  to minimize any difference between the measurements and the estimated values. For example, the terminal  104  may compare the measurements obtained at a plurality of selected depths to the values estimated for the plurality of selected depths to produce a best fit model. Accordingly, the terminal  104  may re-calibrate the forward model of the drilling behavior of the BHA  130  by comparing the measurements to the estimated values. 
     In an embodiment, in step  210 , the terminal  104  may determine how curvature of the drilling is affected by variance in the toolface orientation. The terminal  104  may use the measurements of the toolface orientation obtained by the toolface sensor  180  to determine variation of the toolface orientation from expected values. Then, the terminal  104  may use the measurements of the inclination and/or the azimuth obtained by the D&amp;I sensor  172  to determine a correlation between the variance of the toolface orientation from the expected values and any variation of the measurements of the inclination and/or the azimuth from the expected values. The correlation between the variance of the toolface orientation from the expected values and any variation of the measurements of the inclination and/or the azimuth from the expected values may be used to calibrate the forward model of the drilling behavior of the BHA  130 . 
     In an embodiment, the terminal  104  may use a variance threshold to determine the accuracy of the model. If the difference between the measurements and the estimated values is equal to or less than the variance threshold, the terminal  104  may determine that the model has sufficient accuracy. If the difference between the measurements and the estimated values is more than the variance threshold, the terminal  104  may adjust the model to reduce the difference to below the variance threshold and/or may continue to calibrate the model using data obtained subsequent to the comparison. 
     Referring again to  FIG. 2 , in step  220 , the terminal  104  may estimate a position of the drill bit  110  at one or more depths using the forward model of the drilling behavior of the BHA  130  calibrated in step  210 . For example, the terminal  104  may estimate the azimuth, the inclination and/or the toolface orientation for the drill bit  110  at one or more depths. In an embodiment which determines the accuracy of the model, the terminal  104  may use the model to estimate the azimuth and/or the inclination of the drill bit  110  if the terminal  104  determines that the model has sufficient accuracy. As generally shown in  FIG. 3 , the terminal  104  may generate an extrapolated curve  292  to indicate estimated values for the azimuth and/or the inclination of the drill bit  110 . 
     For a selected depth, the terminal  104  may use the model and/or the drilling parameters set forth by the well plan for the selected depth to determine the estimated values for the azimuth and/or the inclination of the drill bit  110  at the selected depth. For example, the terminal  104  may determine the estimated values using the model, the WOB at the selected depth, properties of the formation through which the BHA  130  drills at the selected depth, the geometry of the BHA  130 , the flow rate of the drilling fluid  20  at the selected depth, the rotation speed of the drill string  108  at the selected depth, operation mode of the drill string  108  as sliding or rotating at the selected depth, the rotation speed of the drill bit  110  at the selected depth, and/or the like. 
     In an embodiment, the terminal  104  may estimate a position of the drill bit  110  at one or more depths by estimating a direction rate of change and/or an inclination rate of change at the drill bit  110 . The terminal  104  may use the model, the measurements and/or the drilling parameters established by the well plan to estimate the direction rate of change and/or the inclination rate of change. The terminal  104  may use the direction rate of change and/or the inclination rate of change with the D&amp;I measurements to estimate the position of the drill bit  110  at one or more depths. 
     As generally shown in step  230 , the terminal  104  may compare the estimated position of the drill bit  110  to the well plan. For example, the terminal  104  may compare the estimated values for the azimuth and/or the inclination of the drill bit  110  to the well plan. The terminal  104  may compare the estimated values for the azimuth and/or the inclination to the closest point on the drilling path established by the well plan. Alternatively, the terminal  104  may compare the estimated values for the azimuth and/or the inclination to the target location established by the well plan. Based on comparison of the well plan to the estimated values for the azimuth and/or the inclination, the terminal  104  may determine desired drilling behavior, such as, for example, well curvature and/or toolface orientation. The well curvature determined by the terminal  104  may be build curvature and/or turn curvature. For example, the terminal  104  may determine the drilling behavior which will direct the drill bit  110  to the target location established by the well plan or to the closest point on the drilling path established by the well plan. 
     As generally shown in step  240 , the terminal  104  may determine a recommended toolface orientation for sliding and/or may determine a recommended rotating/sliding ratio. For example, the terminal  104  may use the desired drilling behavior determined in step  230  in an inverse application of the forward model of the drilling behavior of the BHA  130  determined in step  210  to determine the recommended toolface orientation for sliding and/or the recommended rotating/sliding ratio. The terminal  104  may determine a recommended number of intervals of sliding and/or a recommended number of intervals of rotating over a specified time period to conform the directional drilling to the well plan. In addition, the terminal  104  may determine an amount of time for each of the intervals and/or a total amount of time in which to use the recommended rotating/sliding ratio. In an embodiment, the terminal  104  may determine a recommended WOB and/or a recommended flow rate of the drilling fluid  20  to prevent motor stalling and/or to conform the directional drilling to the well plan. 
     As generally shown in step  250 , the drill bit  110  may drill ahead using the recommended toolface orientation for sliding and/or the recommended rotating/sliding ratio determined in step  240 . In an embodiment, the terminal  104  may automatically implement the recommended toolface orientation for sliding and/or the recommended rotating/sliding ratio without the need for user input. The terminal  104  may automatically implement the recommended toolface orientation for sliding and/or the recommended rotating/sliding ratio by automatically transmitting one or more control signals. Moreover, the terminal  104  may automatically implement the recommended WOB and/or the recommended flow rate of the drilling fluid  20 . 
     For example, the terminal  104  may implement the recommended toolface orientation for sliding and/or the recommended rotating/sliding ratio by automatically transmitting controls signals which direct the drill bit  110  to the target location established by the well plan or to the closest point on the drilling path established by the well plan. The terminal  104  may implement the recommended toolface orientation for sliding and/or the recommended rotating/sliding ratio by transmitting control signals which control rotation of the drill string  108  and/or the bent sub  109 . For example, the control signals may control operation of the top drive  118 , the mud motor  111  and/or the mechanical transmission  112 . If the terminal  104  determines a recommended WOB, the terminal  104  may transmit control signals which cause the drill string  108  to have the recommended WOB, such as, for example, by controlling the drawworks  114 . If the terminal  104  determines a recommended flow rate of the drilling fluid  20 , the terminal  104  may transmit control signals which cause the drill string  108  to have the recommended flow rate of the drilling fluid  20 , such as, for example, by controlling the pump  134 . Thus, the terminal  104  may automatically correct for deviation to conform the directional drilling to the well plan. 
     In another embodiment, an operator may use the recommended toolface orientation for sliding, the recommended rotating/sliding ratio, the recommended WOB and/or the recommended flow rate of the drilling fluid  20  to guide the drill bit  110  in step  250 . For example, the terminal  104  may display the recommended toolface orientation for sliding, the recommended rotating/sliding ratio, the recommended WOB and/or the recommended flow rate of the drilling fluid  20  to the operator. Then, the terminal  104  may accept user input from the operator to control the drilling operation. For example, the operator may control the top drive  118 , the mud motor  111  and/or the mechanical transmission  112  to achieve the recommended rotating/sliding ratio and/or the recommended toolface orientation. As another example, the operator may control the drawworks  114  to achieve the recommended WOB. As yet another example, the operator may control the pump  134  to achieve the recommended flow rate of the drilling fluid  20 . The terminal  104  may transmit control signals in response to the user input from the operator to effectuate commands of the operator. 
     Therefore, the system  10  and the method  200  may generate a forward model of directional drilling behavior of the BHA  130 . Further, the system  10  and the method  200  may use the model and drilling parameters to estimate a position and an orientation of the drill bit  110 . The estimated position and the estimated orientation may be compared to the well plan to determine desired drilling behavior, and the desired drilling behavior may be used to determine a recommended toolface orientation for sliding and/or recommended intervals of sliding and rotating to conform the directional drilling to the well plan. 
     It should be understood that various changes and modifications to the presently preferred embodiments described herein will be apparent to those having ordinary skill in the art. Such changes and modifications may be made without departing from the spirit and scope of the present disclosure and without diminishing its attendant advantages. It is, therefore, intended that such changes and modifications be covered by the claims.