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BACKGROUND 
     This invention relates generally to subterranean boreholes, and in particular to systems for controlling the operating pressures within subterranean boreholes. 
     Referring to FIG. 1, a typical oil or gas well  10  includes a wellbore  12  that traverses a subterranean formation  14  and includes a wellbore casing  16 . During operation of the well  10 , a drill pipe  18  may be positioned within the wellbore  12  in order to inject fluids such as, for example, drilling mud into the wellbore. As will be recognized by persons having ordinary skill in the art, the end of the drill pipe  18  may include a drill bit and the injected drilling mud may used to cool the drill bit and remove particles drilled away by the drill bit. A mud tank  20  containing a supply of drilling mud may be operably coupled to a mud pump  22  for injecting the drilling mud into the drill pipe  18 . The annulus  24  between the wellbore casing  16  and the drill pipe  18  may be sealed in a conventional manner using, for example, a rotary seal  26 . In order to control the operating pressures within the well  10  such as, for example, within acceptable ranges, a choke  28  may be operably coupled to the annulus  24  between the wellbore casing  16  and the drill pipe  18  in order to controllably bleed off pressurized fluidic materials out of the annulus  24  back into the mud tank  20  to thereby create back pressure within the wellbore  12 . The choke  28  is manually controlled by a human operator  30  to maintain one or more of the following operating pressures within the well  10  within acceptable ranges: (1) the operating pressure within the annulus  24  between the wellbore casing  16  and the drill pipe  18 —commonly referred to as the casing pressure (CSP); (2) the operating pressure within the drill pipe  18 —commonly referred to as the drill pipe pressure (DPP); and (3) the operating pressure within the bottom of the wellbore  12 —commonly referred to as the bottom hole pressure (BHP). In order to facilitate the manual human control  30  of the CSP, the DPP, and the BHP, sensors,  32   a ,  32   b , and  32   c , respectively, may be positioned within the well  10  that provide signals representative of the actual values for CSP, DPP, and/or BHP for display on a conventional display panel  34 . Typically, the sensors,  32   a  and  32   b , for sensing the CSP and DPP, respectively, are positioned within the annulus  24  and drill pipe  18 , respectively, adjacent to a surface location. The operator  30  may visually observe one of the more operating pressures, CSP, DPP, and/or BHP, using the display panel  34  and attempt to manually maintain the operating pressures within predetermined acceptable limits by manually adjusting the choke  28 . If the CSP, DPP, and/or the BHP are not maintained within acceptable ranges then an underground blowout can occur thereby potentially damaging the production zones within the subterranean formation  14 . The manual operator control  30  of the CSP, DPP, and/or the BHP is imprecise, unreliable, and unpredictable. As a result, underground blowouts occur thereby diminishing the commercial value of many oil and gas wells. 
     The present invention is directed to overcoming one or more of the limitations of existing systems for controlling the operating pressures of subterranean boreholes. 
     SUMMARY 
     According to an embodiment of the present invention, a method of controlling one or more operating pressures within a subterranean borehole that includes a tubular member positioned within the borehole that defines an annulus between the tubular member and the borehole, a sealing member for sealing the annulus between the tubular member and the borehole, a pump for pumping fluidic materials into the tubular member, and an automatic choke for controllably releasing fluidic materials out of the annulus between the tubular member and the borehole is provided that includes sensing an operating pressure within the tubular member and generating an actual tubular member pressure signal representative of the actual operating pressure within the tubular member, comparing the actual tubular member pressure signal with a target tubular member pressure signal representative of a target operating pressure within the tubular member and generating an error signal representative of the difference between the actual tubular member pressure signal and the target tubular member pressure signal, and processing the error signal to generate a set point pressure signal for controlling the operation of the automatic choke. 
     The present embodiments of the invention provide a number of advantages. For example, the ability to control the DPP also permits control of the BHP. Furthermore, the use of a PID controller having lag compensation and/or feedforward control enhances the operational capabilities and accuracy of the control system. In addition, the monitoring of the system transient response and modeling the overall transfer function of the system permits the operation of the PID controller to be further adjusted to respond to perturbations in the system. Finally, the determination of convergence, divergence, or steady state offset between the overall transfer function of the system and the controlled variables permits further adjustment of the PID controller to permit enhanced control system response characteristics. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     FIG. 1 is a schematic illustration of an embodiment of a conventional oil or gas well. 
     FIG. 2 is a schematic illustration of an embodiment of a system for controlling the operating pressures within a oil or gas well. 
     FIG. 3 is a schematic illustration of an embodiment of the automatic choke of the system of FIG.  2 . 
     FIG. 4 is a schematic illustration of an embodiment of the control system of the system of FIG.  2 . 
     FIG. 5 is a schematic illustration of another embodiment of a system for controlling the operating pressures within an oil or gas well. 
     FIG. 6 is a schematic illustration of another embodiment of a system for controlling the operating pressures within an oil or gas well. 
     FIG. 7 is a schematic illustration of another embodiment of a system for controlling the operating pressures within an oil or gas well. 
     FIG. 8 is a schematic illustration of another embodiment of a system for controlling the operating pressures within an oil or gas well. 
    
    
     DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     Referring to FIGS. 2-4, the reference numeral  100  refers, in general, to an embodiment of a system for controlling the operating pressures within the oil or gas well  10  that includes an automatic choke  102  for controllably bleeding off the pressurized fluids from the annulus  24  between the wellbore casing  16  and the drill pipe  18  to the mud tank  20  to thereby create back pressure within the wellbore  12  and a control system  104  for controlling the operation of the automatic choke. 
     As illustrated in FIG. 3, the automatic choke  102  includes a movable valve element  102   a  that defines a continuously variable flow path depending upon the position of the valve element  102   a . The position of the valve element  102   a  is controlled by a first control pressure signal  102   b , and an opposing second control pressure signal  102   c . In an exemplary embodiment, the first control pressure signal  102   b  is representative of a set point pressure (SPP) that is generated by the control system  104 , and the second control pressure signal  102   c  is representative of the CSP. In this manner, if the CSP is greater than the SPP, pressurized fluidic materials within the annulus  24  of the well  10  are bled off into the mud tank  20 . Conversely, if the CSP is equal to or less than the SPP, then the pressurized fluidic materials within the annulus  24  of the well  10  are not bled off into the mud tank  20 . In this manner, the automatic choke  102  provides a pressure regulator than can controllably bleed off pressurized fluids from the annulus  24  and thereby also controllably create back pressure in the wellbore  12 . In an exemplary embodiment, the automatic choke  102  is further provided substantially as described in U.S. Pat. No. 6,253,787, the disclosure of which is incorporated herein by reference. 
     As illustrated in FIG. 4, the control system  104  includes a conventional air supply  104   a  that is operably coupled to a conventional manually operated air pressure regulator  104   b  for controlling the operating pressure of the air supply. A human operator  104   c  may manually adjust the air pressure regulator  104   b  to generate a pneumatic SPP. The pneumatic SPP is then converted to a hydraulic SPP by a conventional pneumatic to hydraulic pressure converter  104   d . The hydraulic SPP is then used to control the operation of the automatic choke  102 . 
     Thus, the system  100  permits the CSP to be automatically controlled by the human operator  104   c  selecting the desired SPP. The automatic choke  102  then regulates the CSP as a function of the selected SPP. 
     Referring to FIG. 5, an alternative embodiment of a system  200  for controlling the operating pressures within the oil or gas well  10  includes a human operator visual feedback  202  that monitors the actual DPP value within the drill pipe  18  using the display panel  34 . The actual DPP value is then read by the human operator  202  and compared with a predetermined target DPP value by the human operator to determine the error in the actual DPP. The control system  104  may then be manually operated by a human operator to adjust the SPP as a function of the amount of error in the actual DPP. The adjusted SPP is then processed by the automatic choke  102  to control the actual CSP. The actual CSP then is processed by the well  10  to adjust the actual DPP. Thus, the system  200  maintains the actual DPP within a predetermined range of acceptable values. Furthermore, because there is a closer correlation between DPP and BHP than between CSP and BHP, the system  200  is able to control the BHP more effectively than the system  100 . 
     Referring to FIG. 6, another alternative embodiment of a system  300  for controlling the operating pressures within the oil or gas well  10  includes a sensor feedback  302  that monitors the actual DPP value within the drill pipe  18  using the output signal of the sensor  32   b . The actual DPP value provided by the sensor feedback  302  is then compared with the target DPP value to generate a DPP error that is processed by a proportional-integral-differential (PID) controller  304  to generate an hydraulic SPP. 
     As will be recognized by persons having ordinary skill in the art, a PID controller includes gain coefficients, Kp, Ki, and Kd, that are multiplied by the error signal, the integral of the error signal, and the differential of the error signal, respectively. In an exemplary embodiment, the PID controller  304  also includes a lag compensator and/or feedforward control. In an exemplary embodiment, the lag compensator is directed to: (1) compensating for lags due to the wellbore fluid pressure dynamics (i.e., a pressure transient time (PTT) lag); and/or (2) compensating for lags due to the response lag between the input to the automatic choke  102  (i.e., the numerical input value for SPP provided by the PID controller  304 ) and the output of the automatic choke (i.e., the resulting CSP). The PTT refers to the amount of time for a pressure pulse, generated by the opening or closing of the automatic choke  102 , to travel down the annulus  24  and back up the interior of the drill pipe  18  before manifesting itself by altering the DPP at the surface. The PTT further varies, for example, as a function of: (1) the operating pressures in the well  10 ; (2) the kick fluid volume, type, and dispersion; (3) the type and condition of the mud; and (4) the type and condition of the subterranean formation  14 . 
     As will be recognized by persons having ordinary skill in the art, feedforward control refers to a control system in which set point changes or perturbations in the operating environment can be anticipated and processed independent of the error signal before they can adversely affect the process dynamics. In an exemplary embodiment, the feedforward control anticipates changes in the SPP and/or perturbations in the operating environment for the well  10 . 
     The hydraulic SPP is then processed by the automatic choke  102  to control the actual CSP. The actual CSP is then processed by the well  10  to adjust the actual DPP. Thus, the system  300  maintains the actual DPP within a predetermined range of acceptable values. Furthermore, because the PID controller  304  of the system  300  is more responsive, accurate, and reliable than the control system  104  of the system  200 , the system  300  is able to control the DPP and BHP more effectively than the system  200 . 
     Referring to FIG. 7, an embodiment of an adaptive system  400  for controlling the operating pressures within the oil or gas well  10  includes a sensor feedback  402  that monitors the actual DPP value within the drill pipe  18  using the output signal of the sensor  32   b . The actual DPP value provided by the sensor feedback  402  is then compared with the target DPP value to generate a DPP error that is processed by a proportional-integral-differential (PID) controller  404  to generate an hydraulic SPP. In an exemplary embodiment, the PID controller  404  further includes a lag compensator and/or feedforward control. In an exemplary embodiment, the lag compensator is directed to: (1) compensating for lags due to the wellbore fluid pressure dynamics (i.e., the pressure transient time lag); and/or (2) compensating for lags due to the response lag between the input to the automatic choke  102  (i.e., the numerical input value for SPP provided by the PID controller  404 ) and the output of the automatic choke (i.e., the resulting CSP). In an exemplary embodiment, the feedforward control anticipates changes in the SPP and/or perturbations in the operating environment for the well  10 . 
     The hydraulic SPP is then processed by the automatic choke  102  to control the actual CSP. The actual CSP is then processed by the well  10  to adjust the actual DPP. An identification and/or pressure transient time (PTT) measurement control block  406  monitors the actual CSP and/or DPP in order to: (1) quantify the controlled parameters of the system  400  based upon past input and output responses in order to determine the transient behavior of the CSP and/or DPP; and/or (2) determine the PTT. 
     The identification and/or PTT measurements are then processed by a remodeling and decision control block  408  in order to adaptively modify the gain coefficients of the PID controller  404 . In particular, the remodeling and decision control block  408  processes the identification and/or PTT measurements provided by the identification and/or PTT measurement control block  406  to generate a model of the overall transfer function for the system  400  and determine how that model may be modified to improve the overall performance of the system. The gain coefficients of the PID controller  404  are then adjusted by the remodeling and decision control block  408  in order to improve the overall performance of the system. 
     In an exemplary embodiment, the PID controller  404 , the identification and/or PTT measurement control block  406 , and remodeling and decision control block  408  are provided by a programmable controller that implements corresponding control software and includes conventional input and output signal processing such as, for example, digital to analog (D/A) and analog to digital (A/D) conversion. 
     Thus, the system  400  characterizes the transient behavior of the CSP and/or the DPP and then updates the modeling of the overall transfer function for the system. Based upon the updated model of the overall transfer function for the system  400 , the system  400  then modifies the gain coefficients for the PID controller  404  in order to optimally control the DPP and BHP. In this manner, the system  400  is highly effective at adaptively controlling the DPP and BHP to thereby respond to perturbations  410  that may act upon the well  10 . 
     Referring to FIG. 8, an alternative embodiment of an adaptive system  500  for controlling the operating pressures within the oil or gas well  10  includes a sensor feedback  502  that monitors the actual DPP value within the drill pipe  18  using the output signal of the sensor  32   b . The actual DPP value provided by the sensor feedback  502  is then compared with the target DPP value to generate a DPP error that is processed by a proportional-integral-differential (PID) controller  504  to generate an hydraulic SPP. In an exemplary embodiment, the PID controller  504  further includes a lag compensator and/or feedforward control. In an exemplary embodiment, the lag compensator is directed to: (1) compensating for lags due to the wellbore fluid pressure dynamics (i.e., the pressure transient time lag); and/or (2) compensating for lags due to the response lag between the input to the automatic choke  102  (i.e., the numerical input value for SPP provided by the PID controller  504 ) and the output of the automatic choke (i.e., the resulting CSP). In an exemplary embodiment, the feedforward control anticipates changes in the SPP and/or perturbations in the operating environment for the well  10 . 
     The hydraulic SPP is then processed by the automatic choke  102  to control the actual CSP. The actual CSP is then processed by the well  10  to adjust the actual DPP. An identification and/or pressure transient time (PTT) measurement control block  506  is also provided that monitors the actual CSP and/or DPP in order to: (1) quantify the parameters of the system  500  related to the transient behavior of the system; and/or (2) determine the PTT. 
     The identification and/or PTT measurements are then processed by a remodeling and decision control block  508  in order to adaptively modify the gain coefficients of the PID controller  504 . In particular, the remodeling and decision control block  508  processes the identification and/or PTT measurements provided by the identification and/or PTT measurement control block  506  to generate a model of the overall transfer function for the system  500  and determine how that model may be modified to improve the overall performance of the system. The gain coefficients of the PID controller  504  are then adjusted by the remodeling and decision control block  508  in order to improve the overall performance of the system. 
     An estimation, convergence, and verification control block  510  is also provided that monitors the actual BHP value using the output signal of the sensor  32   c  in order to compare the theoretical response of the system  500  with the actual response of the system and thereby determine if the theoretical response of the system is converging toward or diverging from the actual response of the system. If the estimation, convergence, and verification control block  510  determines that there is convergence, divergence or a steady state offset between the theoretical and actual response of the system  500 , then the estimation, convergence, and verification control block may then modify the operation of the PID controller  504  and the remodeling and decision control block  508 . 
     In an exemplary embodiment, the PID controller  504 , the identification and/or PTT measurement control block  506 , the remodeling and decision control block  508 , and the estimation, convergence and verification control block  510  are provided by a programmable controller that implements corresponding control software and includes conventional input and output signal processing such as, for example, D/A and A/D conversion. 
     Thus, the system  500  characterizes the transient behavior of the CSP and/or the DPP and then updates the modeling of the overall transfer function for the system. Based upon the updated model of the overall transfer function for the system, the system  500  then modifies the gain coefficients for the PID controller  504  in order to optimally control the DPP and BHP. The system  500  further adjusts the gain coefficients of the PID controller  504  and the modeling of the overall transfer function of the system as a function of the degree of convergence, divergence, or steady state offset between the theoretical and actual response of the system. In this manner, the system  500  is more effective at adaptively controlling the DPP and BHP to thereby respond to perturbations  512  that may act upon the well  10  than the system  400 . 
     As will be recognized by persons having ordinary skill in the art, having the benefit of the present disclosure, the operation of placing a tubular member into a subterranean borehole is common to the formation and/or operation of, for example, oil and gas wells, mine shafts, underground structural supports, and underground pipelines. Furthermore, as will also be recognized by persons having ordinary skill in the art, having the benefit of the present disclosure, the operating pressures within subterranean structures such as, for example, oil and gas wells, mine shafts, underground structural supports and underground pipelines, typically must be controlled before, during, or after their formation. Thus, the teachings of the present disclosure may be used to control the operating pressures within subterranean structures such as, for example, oil and gas wells, mine shafts, underground structural supports, and underground pipelines. 
     The present embodiments of the invention provide a number of advantages. For example, the ability to control the DPP also permits control of the BHP. Furthermore, the use of a PID controller having lag compensating and/or feedforward control enhances the operational capabilities and accuracy of the control system. In addition, the monitoring of the system transient response and modeling the overall transfer function of the system permits the operation of the PID controller to be further adjusted to respond to perturbations in the system. Finally, the determination of convergence, divergence, or steady state offset between the overall transfer function of the system and the controlled variables permits further adjustment of the PID controller to permit enhanced response characteristics. 
     It is understood that variations may be made in the foregoing without departing from the scope of the invention. For example, any choke capable of being controlled with a set point signal may be used in the systems  100 ,  200 ,  300 ,  400 , and  500 . Furthermore, the automatic choke  102  may be controlled by a pneumatic, hydraulic, electric, and/or a hybrid actuator and may receive and process pneumatic, hydraulic, electric, and/or hybrid set point and control signals. In addition, the automatic choke  102  may also include an embedded controller that provides at least part of the remaining control functionality of the systems  300 ,  400 , and  500 . Furthermore, the PID controllers,  304 ,  404 , and  504  and the control blocks,  406 ,  408 ,  506 ,  508 , and  510  may, for example, be analog, digital, or a hybrid of analog and digital, and may be implemented, for example, using a programmable general purpose computer, or an application specific integrated circuit. Finally, as discussed above, the teachings of the systems  100 ,  200 ,  300 ,  400  and  500  may be applied to the control of the operating pressures within any borehole formed within the earth including, for example, a oil or gas production well, an underground pipeline, a mine shaft, or other subterranean structure in which it is desirable to control the operating pressures. 
     Although illustrative embodiments of the invention have been shown and described, a wide range of modification, changes and substitution is contemplated in the foregoing disclosure. In some instances, some features of the present invention may be employed without a corresponding use of the other features. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the invention.

Summary:
A borehole includes a tubular member, a sealing member for sealing an annulus between the tubular member and the borehole, a pump for pumping fluidic materials into the tubular member, and an automatic choke for controllably releasing pressurized fluidic materials out of the annulus. A system and method monitor the operating pressure within the tubular member and compare the actual operating pressure with a desired operating pressure. The difference between the actual and desired operating pressure is then processed to control the operation of the automatic choke to thereby controllably bleed pressurized fluidic materials out of the annulus thereby creating back pressure within the borehole.