Patent Publication Number: US-2015083401-A1

Title: Drilling operation control using multiple concurrent hydraulics models

Description:
TECHNICAL FIELD 
     This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in one example described below, more particularly provides for wellbore pressure control using multiple concurrently-running hydraulics models. 
     BACKGROUND 
     A hydraulics model can be used to control a drilling operation, for example, in managed pressure, underbalanced, overbalanced or optimized pressure drilling. Typically, an objective is to maintain wellbore pressure at a desired value during the drilling operation. Unfortunately, such hydraulics models are unlikely to be equally adept at outputting setpoints for controlling the drilling operation in different circumstances (e.g., drilling ahead, taking an influx, fluid loss, etc.). 
     Therefore, it will be appreciated that improvements are continually needed in the art of controlling drilling operations. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a representative partially cross-sectional view of a well drilling system and associated method which can embody principles of this disclosure. 
         FIG. 2  is a representative schematic view of another example of the well drilling system and method. 
         FIG. 3  is a representative schematic view of a pressure and flow control system which may be used with the system and method of  FIGS. 1 &amp; 2 . 
         FIG. 4  is a representative flowchart for a method of controlling a drilling operation. 
         FIGS. 5 &amp; 6  are representative flowcharts for further examples of the drilling operation control method. 
     
    
    
     DETAILED DESCRIPTION 
     Representatively illustrated in  FIG. 1  is a well drilling system  10  and associated method which can embody principles of this disclosure. However, it should be clearly understood that the system  10  and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system  10  and method described herein and/or depicted in the drawings. 
     In the  FIG. 1  example, a wellbore  12  is drilled by rotating a drill bit  14  on an end of a drill string  16 . Drilling fluid  18 , commonly known as mud, is circulated downward through the drill string  16 , out the drill bit  14  and upward through an annulus  20  formed between the drill string and the wellbore  12 , in order to cool the drill bit, lubricate the drill string, remove cuttings and provide a measure of bottom hole pressure control. A non-return valve  21  (typically a flapper-type check valve) prevents flow of the drilling fluid  18  upward through the drill string  16  (e.g., when connections are being made in the drill string). 
     Control of wellbore pressure is very important in managed pressure drilling, and in other types of drilling operations. Preferably, the wellbore pressure is precisely controlled to prevent excessive loss of fluid into the earth formation surrounding the wellbore  12 , undesired fracturing of the formation, undesired influx of formation fluids into the wellbore, etc. 
     In typical managed pressure drilling, it is desired to maintain the wellbore pressure just slightly greater than a pore pressure of the formation penetrated by the wellbore, without exceeding a fracture pressure of the formation. This technique is especially useful in situations where the margin between pore pressure and fracture pressure is relatively small. 
     In typical underbalanced drilling, it is desired to maintain the wellbore pressure somewhat less than the pore pressure, thereby obtaining a controlled influx of fluid from the formation. In typical overbalanced drilling, it is desired to maintain the wellbore pressure somewhat greater than the pore pressure, thereby preventing (or at least mitigating) influx of fluid from the formation. 
     Nitrogen or another gas, or another lighter weight fluid, may be added to the drilling fluid  18  for pressure control. This technique is useful, for example, in underbalanced drilling operations. 
     In the system  10 , additional control over the wellbore pressure is obtained by closing off the annulus  20  (e.g., isolating it from communication with the atmosphere and enabling the annulus to be pressurized at or near the surface) using a rotating control device  22  (RCD). The RCD  22  seals about the drill string  16  above a wellhead  24 . Although not shown in  FIG. 1 , the drill string  16  would extend upwardly through the RCD  22  for connection to, for example, a rotary table (not shown), a standpipe line  26 , kelley (not shown), a top drive and/or other conventional drilling equipment. 
     The drilling fluid  18  exits the wellhead  24  via a wing valve  28  in communication with the annulus  20  below the RCD  22 . The fluid  18  then flows through mud return lines  30 ,  73  to a choke manifold  32 , which includes redundant chokes  34  (only one of which might be used at a time). Backpressure is applied to the annulus  20  by variably restricting flow of the fluid  18  through the operative choke(s)  34 . 
     The greater the restriction to flow through the choke  34 , the greater the backpressure applied to the annulus  20 . Thus, downhole pressure (e.g., pressure at the bottom of the wellbore  12 , pressure at a downhole casing shoe, pressure at a particular formation or zone, etc.) can be conveniently regulated by varying the backpressure applied to the annulus  20 . Hydraulics models can be used, as described more fully below, to determine a pressure applied to the annulus  20  at or near the surface which will result in a desired downhole pressure, so that an operator (or an automated control system) can readily determine how to regulate the pressure applied to the annulus at or near the surface (which can be conveniently measured) in order to obtain the desired downhole pressure. 
     Pressure applied to the annulus  20  can be measured at or near the surface via a variety of pressure sensors  36 ,  38 ,  40 , each of which is in communication with the annulus. Pressure sensor  36  senses pressure below the RCD  22 , but above a blowout preventer (BOP) stack  42 . Pressure sensor  38  senses pressure in the wellhead below the BOP stack  42 . Pressure sensor  40  senses pressure in the mud return lines  30 ,  73  upstream of the choke manifold  32 . 
     Another pressure sensor  44  senses pressure in the standpipe line  26 . Yet another pressure sensor  46  senses pressure downstream of the choke manifold  32 , but upstream of a separator  48 , shaker  50  and mud pit  52 . Additional sensors include temperature sensors  54 ,  56 , Coriolis flowmeter  58 , and flowmeters  62 ,  64 ,  66 . 
     Not all of these sensors are necessary. For example, the system  10  could include only two of the three flowmeters  62 ,  64 ,  66 . However, input from all available sensors can be useful to the hydraulics models in determining what the pressure applied to the annulus  20  should be during the drilling operation. 
     Other sensor types may be used, if desired. For example, it is not necessary for the flowmeter  58  to be a Coriolis flowmeter, since a turbine flowmeter, acoustic flowmeter, or another type of flowmeter could be used instead. 
     In addition, the drill string  16  may include its own sensors  60 , for example, to directly measure downhole pressure. Such sensors  60  may be of the type known to those skilled in the art as pressure while drilling (PWD), measurement while drilling (MWD) and/or logging while drilling (LWD). These drill string sensor systems generally provide at least pressure measurement, and may also provide temperature measurement, detection of drill string characteristics (such as vibration, weight on bit, stick-slip, etc.), formation characteristics (such as resistivity, density, etc.) and/or other measurements. Various forms of wired or wireless telemetry (acoustic, pressure pulse, electromagnetic, etc.) may be used to transmit the downhole sensor measurements to the surface. 
     Additional sensors could be included in the system  10 , if desired. For example, another flowmeter  67  could be used to measure the rate of flow of the fluid  18  exiting the wellhead  24 , another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of a rig mud pump  68 , etc. 
     Fewer sensors could be included in the system  10 , if desired. For example, the output of the rig mud pump  68  could be determined by counting pump strokes, instead of by using the flowmeter  62  or any other flowmeters. 
     Note that the separator  48  could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a “poor boy degasser”). However, the separator  48  is not necessarily used in the system  10 . 
     The drilling fluid  18  is pumped through the standpipe line  26  and into the interior of the drill string  16  by the rig mud pump  68 . The pump  68  receives the fluid  18  from the mud pit  52  and flows it via a standpipe manifold  70  to the standpipe  26 . The fluid  18  then circulates downward through the drill string  16 , upward through the annulus  20 , through the mud return lines  30 ,  73 , through the choke manifold  32 , and then via the separator  48  and shaker  50  to the mud pit  52  for conditioning and recirculation. 
     Note that, in the system  10  as so far described above, the choke  34  cannot be used to control backpressure applied to the annulus  20  for control of the downhole pressure, unless the fluid  18  is flowing through the choke. In conventional overbalanced drilling operations, a lack of fluid  18  flow will occur, for example, whenever a connection is made in the drill string  16  (e.g., to add another length of drill pipe to the drill string as the wellbore  12  is drilled deeper), and the lack of circulation will require that downhole pressure be regulated solely by the density of the fluid  18 . 
     In the system  10 , however, flow of the fluid  18  through the choke  34  can be maintained, even though the fluid does not circulate through the drill string  16  and annulus  20 , while a connection is being made in the drill string. Thus, pressure can still be applied to the annulus  20  by restricting flow of the fluid  18  through the choke  34 , even though a separate backpressure pump may not be used. 
     When fluid  18  is not circulating through drill string  16  and annulus  20  (e.g., when a connection is made in the drill string), the fluid is flowed from the pump  68  to the choke manifold  32  via a bypass line  72 ,  75 . Thus, the fluid  18  can bypass the standpipe line  26 , drill string  16  and annulus  20 , and can flow directly from the pump  68  to the mud return line  30 , which remains in communication with the annulus  20 . Restriction of this flow by the choke  34  will thereby cause pressure to be applied to the annulus  20  (for example, in typical managed pressure drilling). 
     As depicted in  FIG. 1 , both of the bypass line  75  and the mud return line  30  are in communication with the annulus  20  via a single line  73 . However, the bypass line  75  and the mud return line  30  could instead be separately connected to the wellhead  24 , for example, using an additional wing valve (e.g., below the RCD  22 ), in which case each of the lines  30 ,  75  would be directly in communication with the annulus  20 . 
     Although this might require some additional piping at the rig site, the effect on the annulus pressure would be essentially the same as connecting the bypass line  75  and the mud return line  30  to the common line  73 . Thus, it should be appreciated that various different configurations of the components of the system  10  may be used, and still remain within the scope of this disclosure. 
     Flow of the fluid  18  through the bypass line  72 ,  75  is regulated by a choke or other type of flow control device  74 . Line  72  is upstream of the bypass flow control device  74 , and line  75  is downstream of the bypass flow control device. 
     Flow of the fluid  18  through the standpipe line  26  is substantially controlled by a valve or other type of flow control device  76 . Since the rate of flow of the fluid  18  through each of the standpipe and bypass lines  26 ,  72  is useful in determining how wellbore pressure is affected by these flows, the flowmeters  64 ,  66  are depicted in  FIG. 1  as being interconnected in these lines. 
     However, the rate of flow through the standpipe line  26  could be determined even if only the flowmeters  62 ,  64  were used, and the rate of flow through the bypass line  72  could be determined even if only the flowmeters  62 ,  66  were used. Thus, it should be understood that it is not necessary for the system  10  to include all of the sensors depicted in  FIG. 1  and described herein, and the system could instead include additional sensors, different combinations and/or types of sensors, etc. 
     In the  FIG. 1  example, a bypass flow control device  78  and flow restrictor  80  may be used for filling the standpipe line  26  and drill string  16  after a connection is made in the drill string, and for equalizing pressure between the standpipe line and mud return lines  30 ,  73  prior to opening the flow control device  76 . Otherwise, sudden opening of the flow control device  76  prior to the standpipe line  26  and drill string  16  being filled and pressurized with the fluid  18  could cause an undesirable pressure transient in the annulus  20  (e.g., due to flow to the choke manifold  32  temporarily being lost while the standpipe line and drill string fill with fluid, etc.). 
     By opening the standpipe bypass flow control device  78  after a connection is made, the fluid  18  is permitted to fill the standpipe line  26  and drill string  16  while a substantial majority of the fluid continues to flow through the bypass line  72 , thereby enabling continued controlled application of pressure to the annulus  20 . After the pressure in the standpipe line  26  has equalized with the pressure in the mud return lines  30 ,  73  and bypass line  75 , the flow control device  76  can be opened, and then the flow control device  74  can be closed to slowly divert a greater proportion of the fluid  18  from the bypass line  72  to the standpipe line  26 . 
     Before a connection is made in the drill string  16 , a similar process can be performed, except in reverse, to gradually divert flow of the fluid  18  from the standpipe line  26  to the bypass line  72  in preparation for adding more drill pipe to the drill string  16 . That is, the flow control device  74  can be gradually opened to slowly divert a greater proportion of the fluid  18  from the standpipe line  26  to the bypass line  72 , and then the flow control device  76  can be closed. 
     Note that the flow control device  78  and flow restrictor  80  could be integrated into a single element (e.g., a flow control device having a flow restriction therein), and the flow control devices  76 ,  78  could be integrated into a single flow control device  81  (e.g., a single choke which can gradually open to slowly fill and pressurize the standpipe line  26  and drill string  16  after a drill pipe connection is made, and then open fully to allow maximum flow while drilling). 
     However, since typical conventional drilling rigs are equipped with the flow control device  76  in the form of a valve in the standpipe manifold  70 , and use of the standpipe valve is incorporated into usual drilling practices, the individually operable flow control devices  76 ,  78  preserve the use of the flow control device  76 . The flow control devices  76 ,  78  are at times referred to collectively below as though they are the single flow control device  81 , but it should be understood that the flow control device  81  can include the individual flow control devices  76 ,  78 . 
     Another example is representatively illustrated in  FIG. 2 . In this example, the flow control device  76  is connected upstream of the rig&#39;s standpipe manifold  70 . This arrangement has certain benefits, such as, no modifications are needed to the rig&#39;s standpipe manifold  70  or the line between the manifold and the kelley, the rig&#39;s standpipe bleed valve  82  can be used to vent the standpipe  26  as in normal drilling operations (no need to change procedure by the rig&#39;s crew), etc. 
     The flow control device  76  can be interconnected between the rig pump  68  and the standpipe manifold  70  using, for example, quick connectors  84  (such as, hammer unions, etc.). This will allow the flow control device  76  to be conveniently adapted for interconnection in various rigs&#39; pump lines. 
     A specially adapted fully automated flow control device  76  (e.g., controlled automatically by the controller  96  depicted in  FIG. 3 ) can be used for controlling flow through the standpipe line  26 , instead of using the conventional standpipe valve in a rig&#39;s standpipe manifold  70 . The entire flow control device  81  can be customized for use as described herein (e.g., for controlling flow through the standpipe line  26  in conjunction with diversion of fluid  18  between the standpipe line and the bypass line  72  to thereby control pressure in the annulus  20 , etc.), rather than for conventional drilling purposes. 
     In the  FIG. 2  example, a remotely controllable valve or other flow control device  160  is optionally used to divert flow of the fluid  18  from the standpipe line  26  to the mud return line  30  downstream of the choke manifold  32 , in order to transmit signals, data, commands, etc. to downhole tools (such as the  FIG. 1  bottom hole assembly including the sensors  60 , other equipment, including mud motors, deflection devices, steering controls, etc.). The device  160  is controlled by a telemetry controller  162 , which can encode information as a sequence of flow diversions detectable by the downhole tools (e.g., a certain decrease in flow through a downhole tool will result from a corresponding diversion of flow by the device  160  from the standpipe line  26  to the mud return line  30 ). 
     A suitable telemetry controller and a suitable remotely operable flow control device are provided in the GEO-SPAN(™) system marketed by Halliburton Energy Services, Inc. The telemetry controller  162  can be connected to the INSITE(™) system or other acquisition and control interface  94  in the control system  90 . However, other types of telemetry controllers and flow control devices may be used in keeping with the scope of this disclosure. 
     Note that each of the flow control devices  74 ,  76 ,  78  and chokes  34  are preferably remotely and automatically controllable to maintain a desired downhole pressure by maintaining a desired annulus pressure at or near the surface. However, any one or more of these flow control devices  74 ,  76 ,  78  and chokes  34  could be manually controlled, in keeping with the scope of this disclosure. 
     A pressure and flow control system  90  which may be used in conjunction with the system  10  and associated methods of  FIGS. 1 &amp; 2  is representatively illustrated in  FIG. 3 . The control system  90  is preferably fully automated, although some human intervention may be used, for example, to safeguard against improper operation, initiate certain routines, update parameters, etc. 
     The control system  90  includes multiple hydraulics models  92 , a data acquisition and control interface  94  and a controller  96  (such as a programmable logic controller or PLC, a suitably programmed computer, etc.). Although these elements  92 ,  94 ,  96  are depicted separately in  FIG. 3 , any or all of them could be combined into a single element, or the functions of the elements could be separated into additional elements, other additional elements and/or functions could be provided, etc. 
     Three hydraulics models  92  are illustrated in  FIG. 3 , but any number of hydraulics models may be used. Furthermore, the hydraulics models  92  may be concurrently-running instances of a hydraulics model, instead of separate hydraulics models. As used herein, multiple hydraulics models can refer to both multiple separate hydraulics models and multiple instances of a hydraulics model. 
     The hydraulics models  92  are used in the control system  90  to determine the desired annulus pressure at or near the surface to achieve a desired downhole pressure. Data such as well geometry, fluid properties and offset well information (such as geothermal gradient and pore pressure gradient, etc.) are utilized by the hydraulics models  92  in making this determination, as well as real-time sensor data acquired by the data acquisition and control interface  94 . 
     Thus, there is a continual two-way transfer of data and information between the hydraulics models  92  and the data acquisition and control interface  94 . It is important to appreciate that the data acquisition and control interface  94  operates to maintain a substantially continuous flow of real-time data from the sensors  44 ,  54 ,  66 ,  62 ,  64 ,  60 ,  58 ,  46 ,  36 ,  38 ,  40 ,  56 ,  67  to the hydraulics models  92 , so that the hydraulics models have the information they need to adapt to changing circumstances and to update the desired annulus pressure, and the hydraulics models operate to supply the data acquisition and control interface substantially continuously with values for the desired annulus pressure. 
     A suitable hydraulics model for use as the hydraulics models  92  in the control system  90  is REAL TIME HYDRAULICS (™) or GB SETPOINT (™) marketed by Halliburton Energy Services, Inc. of Houston, Tex. USA. Another suitable hydraulics model is provided under the trade name IRIS (™), and yet another is available from SINTEF of Trondheim, Norway. Any suitable hydraulics models may be used in the control system  90  in keeping with the principles of this disclosure. 
     A suitable data acquisition and control interface for use as the data acquisition and control interface  94  in the control system  90  are SENTRY(™) and INSITE(™) marketed by Halliburton Energy Services, Inc. Any suitable data acquisition and control interface may be used in the control system  90  in keeping with the principles of this disclosure. 
     The controller  96  operates to maintain a desired setpoint annulus pressure by controlling operation of the mud return choke  34  and other devices. When an updated desired annulus pressure is transmitted from the data acquisition and control interface  94  to the controller  96 , the controller uses the desired annulus pressure as a setpoint and controls operation of the choke  34  in a manner (e.g., increasing or decreasing flow resistance through the choke as needed) to maintain the setpoint pressure in the annulus  20 . The choke  34  can be closed more to increase flow resistance, or opened more to decrease flow resistance. 
     Maintenance of the setpoint pressure is accomplished by comparing the setpoint pressure to a measured annulus pressure (such as the pressure sensed by any of the sensors  36 ,  38 ,  40 ), and decreasing flow resistance through the choke  34  if the measured pressure is greater than the setpoint pressure, and increasing flow resistance through the choke if the measured pressure is less than the setpoint pressure. Of course, if the setpoint and measured pressures are the same, then no adjustment of the choke  34  is required. This process is preferably automated, so that no human intervention is required, although human intervention may be used, if desired. 
     The controller  96  may also be used to control operation of the standpipe flow control devices  76 ,  78  and the bypass flow control device  74 . The controller  96  can, thus, be used to automate the processes of diverting flow of the fluid  18  from the standpipe line  26  to the bypass line  72  prior to making a connection in the drill string  16 , then diverting flow from the bypass line to the standpipe line after the connection is made, and then resuming normal circulation of the fluid  18  for drilling. Again, no human intervention may be required in these automated processes, although human intervention may be used if desired, for example, to initiate each process in turn, to manually operate a component of the system, etc. 
     Data validation and prediction techniques may be used in the system  90  to guard against erroneous data being used, to ensure that determined values are in line with predicted values, etc. Suitable data validation and prediction techniques are described in International Application No. PCT/US11/59743, although other techniques may be used, if desired. 
     The hydraulics models  92  are used to generate the desired annulus pressure setpoint, based on different considerations. The hydraulics models  92  can have different sets of data input to them from the data acquisition and control interface  94 . The setpoint output by one hydraulics model  92  can be different from the setpoint output by another hydraulics model. 
     For example, one hydraulics model  92  could model typical drilling ahead in a managed pressure drilling operation. Another hydraulics model  92  could model a drill string  16  connection process, or tripping the drill string into or out of the wellbore  12 . Another hydraulics model  92  could model an influx being received into the wellbore  12 . Another hydraulics model  92  could model a loss of fluid from the wellbore  12 . Another hydraulics model  92  could model multiphase flow in the well. Another hydraulics model  92  could model high or low pressure, or high or low flow, conditions. Another hydraulics model  92  could model an optimized rate of penetration for a drilling operation. Another hydraulics model  92  could model an optimized drill bit  14  life for a drilling operation. Any type, number and combination of hydraulics models  92  may be used, as desired. 
     When one of these circumstances occurs (e.g., an influx, fluid loss, drill string connection, etc.), a selector  98  can be operated to select which of the annulus pressure setpoints generated by the multiple hydraulics models  92  is output to the controller  96  for controlling operation of the choke  34 , bypass choke  74 , standpipe valve  76 , and/or standpipe flow control  78 , etc. The selector  98  is depicted separately in  FIG. 3  for clarity, but in actual practice the selector may be part of the data acquisition and control interface  94 , or another portion of the system  90 . 
     The selection of which annulus pressure setpoint is used by the controller  96  can be made manually or automatically, and in response to certain considerations. For example, if a particular objective (e.g., optimum rate of penetration, optimum drill bit life, etc.) is desired, then the corresponding hydraulics model  92  setpoint output may be selected manually. In this manner, the selected hydraulics model  92  setpoint output will be used by the controller  96  to control the drilling system  10  in a manner that accomplishes the particular objective. 
     The selection can be made automatically in other circumstances. For example, if an event detection system detects that an event (such as an influx or fluid loss, etc.) has occurred, or is about to occur, then the corresponding hydraulics model  92  which models such an event can be selected automatically. In this manner, the selected hydraulics model  92  setpoint output will be used by the controller  96  to control the drilling system  10  in a manner that appropriately “handles” the event. 
     The automatic switching from one hydraulics model  92  to another could be performed only after authorization from an operator, if desired. Suitable event detection systems are described in International Application Nos. PCT/US09/52227 and PCT/US11/42917. Of course, other event detection systems may be used, if desired. 
     Manual switching from one hydraulics model  92  to another could be done if it appears that one model is more accurately predicting well conditions than another model. For example, one hydraulics model  92  may be predicting wellbore pressure downhole which does not closely match actual measurements made by the downhole sensors  60 . In that case, it may be beneficial to switch to another hydraulics model  92  which is more accurately predicting the wellbore pressure downhole. 
     Referring additionally now to  FIG. 4 , a method  100  which can embody principles of this disclosure is representatively illustrated in flowchart form. The method  100  may be used with the system  10  described above, or it may be used with other drilling systems. 
     In the  FIG. 4  example, multiple hydraulics models  92  are running concurrently in step  102 . The hydraulics models  92  are preferably running concurrently in real time (that is, while the drilling operation is being performed). 
     As discussed above, the multiple hydraulics models  92  may not be separate hydraulics models, but could be multiple instances of a hydraulics model. It is not necessary that the hydraulics models  92  run simultaneously, but preferably the hydraulics models are running concurrently during the drilling operation. 
     In step  104 , the annulus pressure setpoint output by a first hydraulics model  92  is used by the controller  96  for controlling wellbore pressure during the drilling operation. The setpoint output by the first hydraulics model  92  (and any other hydraulics models) may be subject to the data validation and prediction techniques discussed above. The selection of the first hydraulics model  92  setpoint for controlling the drilling operation could be based on any considerations (e.g., an informed choice, a desired objective, a particular circumstance, a detected event, etc.). 
     In step  106 , the selector  98  is used to select an annulus pressure setpoint output by another hydraulics model  92  for controlling the drilling operation. This switch from the first hydraulics model  92  to a second hydraulics model could be performed manually, completely automatically, or automatically upon human authorization, etc. 
     In step  108 , the annulus pressure setpoint output by the second hydraulics model  92  is used by the controller  96  for controlling wellbore pressure during the drilling operation. The selection of the second hydraulics model  92  setpoint for controlling the drilling operation could be based on any considerations (e.g., an informed choice, a change in desired objective, a particular circumstance, a detected event, etc.). 
     Thus, in the method  100 , a switch is made from the annulus pressure setpoint output by the first hydraulics model  92 , to the annulus pressure setpoint output by the second hydraulics model, for input to the controller  96  to control the drilling operation. The switch between the hydraulics models  92  outputs is performed in real time, during the drilling operation. 
     Representatively illustrated in  FIG. 5  is another example of the method  100 , in which an additional step  105  is interposed between steps  104  and  106 . In step  105 , a comparison is made between drilling parameter values predicted by the hydraulics models  92  and actual drilling parameter values measured during the drilling operation. 
     A particular hydraulics model  92  may, for whatever reason, do a better job of predicting actual drilling parameters (such as downhole pressures, etc.) than others of the hydraulics models. In that case, wellbore pressure may be more accurately controlled using that particular hydraulics model  92 . 
     Thus, the switch between the hydraulics models  92  outputs in step  106  is based on the comparison of predicted to actual drilling parameter values performed in step  105 . The switch may be accomplished manually, completely automatically, or automatically upon human authorization, etc. 
     Representatively illustrated in  FIG. 6  is another example of the method  100 , in which the step  105  interposed between steps  104  and  106  comprises an event detection. In response to detection of the event, the selector  98  switches to the output of the hydraulics model  92  which models that particular event. Thus, the controller  96  controls the drilling operation based on the annulus pressure setpoint output by the hydraulics model  92  which models a detected event. 
     As described in the International Application Nos. PCT/US09/52227 and PCT/US11/42917 mentioned above, an event can be a precursor to another event, or can indicate a likelihood that an event is about to occur. In that case, the switching to a corresponding hydraulics model  92  output can prevent the upcoming event from occurring, or at least mitigate its effects on the drilling operation. 
     When an event is detected, an operator may be presented with an indication or warning of the event, at which point the operator can determine whether to switch to a hydraulics model  92  which models that event (or a predicted event). Alternatively, the switch can be performed automatically, or automatically upon human authorization. 
     Note that it is not necessary for the multiple hydraulics models  92  to run simultaneously or concurrently. For example, the hydraulics models  92  could be run sequentially (e.g., daisy-chained) to provide the pressure setpoints periodically. 
     It is also not necessary for the device controlled by the controller  96  to be a flow control device. For example, a backpressure pump or suction pump, or another type of device, could be controlled to maintain the setpoint. 
     It can now be fully appreciated that the above disclosure provides significant advancements to the art of controlling drilling operations. By concurrently running multiple hydraulics models  92 , an operator or automated system can select which of the multiple hydraulics models is appropriate for a given objective, situation, event, etc., occurring during the drilling operation. This enhances the ability of the pressure and flow control system  90  to adapt to changing circumstances. 
     A control system  90  for drilling a subterranean well is described above. In one example, the control system  90  can include multiple hydraulics models  92 , each of the hydraulics models  92  outputting a pressure setpoint, in real time during a drilling operation. 
     The system  90  can also include a controller  96  and a selector  98 . The controller  96  may control operation of at least one device  34 ,  74 ,  76 ,  78 , and the selector  98  may select which of the multiple pressure setpoints is input to the controller  96 . 
     The device can comprise a choke  34  which variably restricts flow from a wellbore  12 , the device  76  may control flow through a standpipe  26 , or the device  74  may control flow between a standpipe  26  and a mud return line  30 . The types of devices, and other types of flow control devices, may be used. 
     The multiple hydraulics models  92  may comprise multiple instances of a same hydraulics model. 
     Also described above is a method  100  of controlling a drilling operation. In one example, the method  100  may comprise running multiple hydraulics models  92  during the drilling operation; and switching between outputs of the multiple hydraulics models  92  to control the drilling operation, the switching being performed during the drilling operation. The hydraulics models may run concurrently. 
     The method can include controlling operation of at least one device  34 ,  74 ,  76 ,  78 , thereby maintaining a pressure at a pressure setpoint output by one of the multiple hydraulics models  92 . The device may comprise a flow control device. 
     The switching step can include switching from a first hydraulics model  92  output to a second hydraulics model  92  output. The switching may be performed in response to a change in an objective of the drilling operation, in response to detection of an event, and/or in response to a comparison between a measured drilling parameter value and the drilling parameter value as predicted by the hydraulics models  92 . 
     The switching can be performed manually or automatically. 
     Another method  100  of controlling a drilling operation described above can include controlling operation of at least one device  34 ,  74 ,  76 ,  78 , thereby maintaining a pressure at a pressure setpoint; and selecting the pressure setpoint from among outputs of multiple hydraulics models  92 . 
     Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example&#39;s features are not mutually exclusive to another example&#39;s features. Instead, the scope of this disclosure encompasses any combination of any of the features. 
     Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used. 
     It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments. 
     In the above description of the representative examples, directional terms (such as “above,” “below,” “upper,” “lower,” etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein. 
     The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.” 
     Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.