Patent Publication Number: US-10787882-B2

Title: Adaptive pressure relief valve set point systems

Description:
BACKGROUND 
     Various well systems may control borehole pressure of a well. In a conventional open well system, piping/riser for returning drilling fluid is typically open to atmospheric pressure. Closed-loop well systems include surface equipment to which the returning drilling fluid can be diverted. Certain managed pressure drilling (MPD) systems may be characterized as closed and pressurized drilling fluid systems. MPD and like systems provide various techniques for regulating borehole pressure, however, existing pressure regulation techniques are often inadequate for certain types of wells and reservoir formations. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure. 
         FIG. 1  is a diagram of an example well system that may employ various principles of the present disclosure. 
         FIG. 2  is a diagram of an example system and network environment that may employ various principles of the present disclosure. 
         FIG. 3  is flow diagram of an example method for calculating and providing dynamic pressure relief valve (PRV) set points in accordance with aspects of the present disclosure. 
         FIG. 4  is chart illustrating dynamic PRV set points plotted with respect to time during a first example of a drilling operation, in accordance with aspects of the present disclosure. 
         FIG. 5  is a chart illustrating dynamic PRV set points plotted with respect to time during a second example of a drilling operation, in accordance with aspects of the present disclosure. 
         FIG. 6  conceptually illustrates a computer system with which certain aspects of the subject technology may be implemented. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure generally relates to well drilling, and more particularly, to controlling borehole pressure of a well during various well drilling operations. 
     Systems and methods are described herein to control pressure relief valve (PRV) set points in real-time during various well and drilling operations. PRV set points may be provided to a PRV controller at certain time intervals during various well and drilling operations such that a series of consecutive PRV set point values account for changes to the pressure profile of the borehole (or wellbore) during such operations. 
     According to embodiments described herein, a dynamic PRV set point system is utilized to enable precise borehole pressure management of wells that have narrow pore pressure, fracture pressure windows, for example. Drilling fluid (e.g., mud) may be circulated down a drill string and up the annulus of the well to create an equivalent circulating density (ECD). During normal drilling operations, the ECD should be greater than the pore pressure of the borehole, but below the pressure that would initiate fracture of the subterranean formation being penetrated. By calculating and providing PRV set points in real-time during various well and drilling operations, non-productive time and costs to remedy issues resulting from improper pressure levels within the borehole (e.g., a stuck pipe of the drill string or damage to the reservoir formation) may be mitigated or avoided altogether. 
     For example, if there is not enough pressure in the borehole, the wall of the borehole may collapse and/or subsurface fluids (e.g., water or gas) may blow through the drilling fluid annulus return. If there is too much pressure in the borehole, the drilling fluid pressure may fracture the subterranean formation. Thus, it can be advantageous in certain wells to keep the pressure in the borehole within a pressure range above pore pressure and below fracture initiation pressure (e.g., drilling margin or pore-pressure-fracture-gradient window). 
     Benefits of a dynamic PRV set point system may be realized in various well operations, for example, cementing operations where ECD and hydrostatic pressure of a cement composition (e.g., a mixture of cement and water, and possibly additives) or cement slurry may require precise control for proper setting while cementing a casing in the subterranean formation and to protect the subterranean formation from fracturation. 
     It is to be further understood that when drilling mature fields, the potential hazard that a reservoir may collapse is exacerbated. Thus, if excess pressure is permitted to build within the borehole and exceeds the fracture gradient, access to some or all of the hydrocarbons in the subterranean formation may be unattainable. 
     As shown in the examples provided herein, dynamically calculating and providing PRV set points to a pressure relief valve can enable precise control of borehole pressure such that pressure is maintained within the pore-pressure-fracture-gradient window even during changing pressure conditions associated with certain well and drilling operations. In this regard, PRV set points are calculated in real-time and provided to a PRV controller, in accordance with aspects of the present disclosure. 
       FIG. 1  illustrates an example well system  100 . A well as used herein with respect to well system  100  can be, but is not limited to, an oil and gas well. In some implementations, well system  100  may include a drilling rig, semi-submersible platform, or fixed platforms, for example. Well system  100  may comprise PRV assembly  110 , wellhead  125 , blowout preventer (BOP) stack  130 , choke manifold  160 , and flow meter assembly  190 . Well system  100  may also comprise additional components illustrated in  FIG. 1 , as well as additional components not expressly identified. 
     In certain embodiments, well system  100  may comprise drill string  120  that is configured to pass through wellhead  125  to drill borehole  105 . Drill string  120  may include a drill bit  122  configured to rotate and pass drilling fluid  102  (e.g., mud) therethrough. In this regard, drilling fluid  102  may be circulated through drill string  120 , out of drill bit  122 , and upward through annulus  108  formed at least partially between an outer surface of drill string  120  and the wall of the borehole  105 . Drilling fluid  102  may be circulated for the purpose of cooling drill bit  122 , lubricating drill string  120 , and removing cuttings from borehole  105 , for example. Drilling string  120  may include one or more sensors  124  to provide bottom hole measurements and one-way flow valve  126  (or similar non-return or check valve). The one or more sensors  124  may include, for example, a pressure while drilling (PWD) sensor, measurement while drilling (MWD) sensor, and/or logging while drilling (LWD) sensor. 
     Well system  100  may be adapted to provide cementing operations, in accordance with certain implementations. For example, upon removing the drill string  124 , a cementing operation may be required to secure one or more lengths of casing from wellhead  125 . The casing is cemented into the borehole  105  by pumping cement through the casing and back up the annulus defined between the exterior off the casing and the wall of the borehole  105 . In this regard, the BOP stack  130  may be used to inject a cement mixture into at least a portion of the annulus. Similarly, liner running operations may be required for extending support of the borehole  105  beyond the casing string. Cementing and liner running operations can benefit from controlling borehole pressure during such respective operations as described herein. 
     BOP stack  130  may be coupled to wellhead  125 , and may include one or more valves to prevent the escape of fluid pressure in the borehole  105 . One or more pressure sensors may be disposed in wellhead  125  to sense pressure in the wellhead  125  below the BOP stack  130 , for example. Well system  100  may further comprise a rotating control device (RCD)  140  disposed above the BOP stack  130 . RCD  140  can seal a top portion of the drill string  120  above wellhead  125  thereby enabling control of the borehole  105  pressure by sealing the annulus  108  such that the annulus  108  is isolated from the atmosphere. 
     Still referring to  FIG. 1 , drill string  120  may extend upwardly through RCD  140  and be operatively coupled to one or more components of rotary table and standpipe assembly  145 . While not shown, rotary table and standpipe assembly  145  may include a rotary table, top drive or swivel, standpipe, standpipe line, Kelly, one or more pumps (i.e., drilling fluid or cement pumps, depending on the application), and/or other top-side drilling equipment. Cement pumps may be used during cementing operations and configured to inject a cement mixture to the borehole  105  for cementing a casing therein. 
     In some embodiments, rotary table and standpipe assembly  145  may include a continuous circulation device. The continuous circulation device may be operatively coupled to the rotary table and configured to provide continuous drilling fluid  102  circulation by allowing one or more drilling fluid pumps (not shown) to stay active when a new drill pipe segment is being connected to drill string  120 . In this regard, the continuous circulation device can be configured to maintain constant downhole pressure during connections (e.g., connection mode). For example, the continuous circulation device may include a sealable internal chamber into which drilling fluid  102  may be pumped from one or more ports. The internal chamber may be configured to enclose a section of the drill string  120  between a junction of a topmost drill pipe and a top drive. As such, continuous drilling fluid  102  circulation is possible by pressurizing the internal chamber with drilling fluid  102  via the one or more ports and then separating the top drive from the topmost drill pipe. Thus, drilling fluid  102  may flow into an open end of the topmost drill pipe via the pressurized chamber of the continuous circulation device. 
     A bottom area of the pressurized chamber can be isolated (e.g., activating blind rams to bisect the internal chamber above the open end of the topmost drill pipe) so that drilling fluid  102  can be continuously injected into the open end of the topmost drill pipe while the top drive is removed from a top area of the internal chamber of the continuous circulation device (e.g., after drilling fluid  102  flow from a standpipe manifold has been stopped). A new section of drill pipe can be connected to the top drive and guided into the continuous circulation device whereby an open end of the new section of drill pipe can be sealingly introduced into the internal chamber when the top area is once again in fluid communication with the pressurized bottom area of the internal chamber (e.g., after release of the blind rams within the internal chamber). Drilling fluid  102  may then be injected into the open end of the topmost drill pipe with the internal chamber via the one or ports of the continuous circulation device and the standpipe via the open end of the new section of drill pipe connected to the top drive. The open end of the topmost drill pipe and the open end of the new section of drill pipe may be guided to establish contact. The new section of drill pipe can then be rotated to sealingly connect the drill pipe segments together. After connection, delivery of drilling fluid  102  via the one or more ports of the continuous circulation device can cease and the internal chamber may be depressurized. Delivery of drilling fluid  102  for circulation through drill string  120  and into the borehole  105  can now be provided solely by the top drive and standpipe connected to the new section of drill pipe (now the topmost drill pipe of the drill string  120 ). 
     In operation, returning drilling fluid  102  may exit the wellhead  125  via one or more valves  132  disposed at a top of the BOP stack  130  below RCD  140 , for example. The one or more valves  132  can be in fluid communication with annulus  108  and return flowline  134 . The return flowline  134  may be coupled to a catcher  150  (e.g., junk catcher) to remove various objects from the returning drilling fluid  102 . For example, catcher  150  may be configured to catch and redirect objects from the returning drilling fluid  102  that have accidentally been injected into or left inside a drill pipe of drill string  120  prior to being put down hole, such as but not limited to gloves, tape, tools, safety glasses, pieces of rubber sealing elements, etc. A flow meter or sensor may be positioned along return flowline  134  proximal to catcher  150 . Catcher  150  may be fluidly coupled to choke manifold  160  via return flowline  164 , for example. Choke manifold  160  includes one or more chokes  166  (e.g., in a redundant formation). One or more flow meters or sensors may be arranged throughout various sections and flowlines of the choke manifold  160 . 
     PRV assembly  110  may include one or more pressure relief valves or similar devices for controlling flow. For example, two pressure relief valves may be used in some implementations so that if a first pressure relief valve malfunctions (e.g., fails to reseat), a second pressure relief valve can be switched into operation. PRV assembly  110  may also include one or more sensors or flow meters, a flush point  112 , and a discharge port  114 . In operation, the one or more pressure relive valves of PRV assembly  110  can discharge drilling fluid  102  to provide pressure relief in excess of a maximum allowable pressure of the well system  100  during sudden changes in pressure of the borehole  105  caused by unexpected, abnormal conditions of the subterraneous formation, for example. 
     Choke manifold  160  may be fluidly coupled to PRV assembly  110  via return flowline  116 , which is fluid communication with return flowline  164 . Backpressure may be applied to the annulus  108  by variably restricting flow of the returning drilling fluid  102  via operation of the one or more chokes  166 . Choke manifold  160  may include an air pressure port  168  for operating the one or more chokes  166 . Further backpressure may be applied by backpressure pump  180 , in accordance with certain embodiments. 
     Backpressure pump  180  may be fluidly coupled to choke manifold  160  via flowline  182 , and may include a charge pump port  184 , cooling water port  186 , and a water discharge port  188 , for example. Similarly, one or more flow meters or sensors may be arranged throughout various sections of backpressure pump  180  including flowline  182 . In this regard, back pressure pump  180  can provide pressure into the return flowlines so that the one or more chokes  166  can remain open during drill pipe connections (e.g., connection mode). Having the one or more chokes  166  open and operable during such time enables the choke manifold  160  to respond changes in borehole pressure during such drill pipe connections and other well drilling operations, for example. 
     In some embodiments, a pump diverter (e.g., rig pump diverter) may be used alternatively or in addition to backpressure pump  180 . For example, the pump diverter may include a manifold with a choke for diverting the flow of drilling fluid  102  from the one or more drilling fluid pumps to provide continuous fluid flow to the choke manifold  160  during drill pipe connections, for example. In this regard, flow of the drilling fluid  102  may be diverted from the standpipe to the choke manifold  160 , thereby applying backpressure to the annulus  108  during various non-drilling well operations to maintain borehole pressure, in accordance with some embodiments. Whether backpressure pump  180  or a pump diverter is utilized in particular embodiments, the dynamic pressure applied by either to the choke manifold  160  can be advantageous over a static choke implementation when drilling operations ramp down or stop, for example. 
     Choke manifold  160  may be fluidly coupled to flow meter assembly  190  via return flowline  192 . Flow meter assembly  190  may include one or more flow meters or sensor for measuring the returning drilling fluid  102 , for example. Flow meter assembly  190  may be fluidly coupled to shaker return flowline  198 , which conveys the drilling fluid to solids control units that remove debris from the drilling fluid. Choke manifold  160  may also be fluidly coupled to drilling fluid-gas separator return flowline  172 . A drilling fluid-gas separator (e.g., a mud gas separator or MGS) may be configured to capture and separate a volume of free gas within the drilling fluid  102 . 
     It is understood that other variations and alternatives are contemplated in addition to well system  100  illustrated in  FIG. 1  and described herein, and therefore any particular example aspect of well system  100  in no way should be read to limit, or define, the scope of the disclosure. 
       FIG. 2  illustrates an example system  200  and network environment that may be used in conjunction with a well, such as but not limited to well system  100  of  FIG. 1 . System  200  may include one or more of a flow and pressure control system  202  (e.g., an MPD control system), a model  204  (e.g., a hydraulic model), a choke interface  206  (e.g., choke programmable logic controller), a gateway interface  208  (e.g., gateway programmable logic controller), a PRV set point control system  212 , and/or a continuous circulation device control system  214 . System  200  may also include a router  210  configured to enable data to be routed between one or more networks, systems, and devices. For example, PRV set point control system  212  may be operatively coupled to model  204  via router  210  as illustrated in  FIG. 2 . However, in other embodiments, PRV set point control system  212  may include model  204  as a software module or application. Similarly, other systems and/or software modules in system  200  may be combined or aggregated in various embodiments (e.g., PRV set point control system  212  and/or continuous circulation device control system  214  may be subsystems or software modules, applications, or the like of flow and pressure control system  202 ). 
     Flow and pressure control system  202  may comprise various processes for controlling flow and pressure associated with drilling operations (e.g., MPD drilling) of well system  100 . In this regard, flow and pressure control system  202  may be operably coupled to various flow meters and/or sensors to receive data therefrom. Flow and pressure control system  202  may be operably coupled to choke interface  206  and gateway interface  208  for activating and controlling various devices and components of well system  100 . For example, choke interface  206  may be operatively coupled to choke manifold  160  and/or other components such as backpressure pump  180 . Gateway interface  208  may be operatively coupled to various valves and switches for controlling the various well and drilling components, as well as to various real-time sensors, meters, gauges, etc., for transmitting and receiving data to and from the drilling control network. 
     Accordingly, flow and pressure control system  202  may cause the one or more chokes  166  to increase or decrease flow resistance. Additionally, flow and pressure control system  202  may be operable to control one or more components of rotary table and standpipe assembly  145  to redirect drilling fluid  102  (e.g., temporarily suspending circulation of drilling fluid  102  in some embodiments or redirecting drilling fluid  102  to maintain circulation in other embodiments). Thus, flow and pressure control system  202  can be configured to control pressure of borehole  105  of well system  100 . 
     Model  204  can be a subsystem or software module of flow and pressure control system  202  or may be a standalone system. In some embodiments, model  204  may be a subsystem or software module of PRV set point control system  212 . Accordingly, model  204  may be of various complexities and comprises various input variables and parameters depending on a particular implementation (e.g., modelling well characteristics from a few pressure and flow input variables, or a comprehensive hydraulic model based on numerous input variables and historical data). 
     Model  204  may be used to determine the desired annulus pressure at or near wellhead  125  to achieve a desired borehole pressure. Data such as but not limited to well geometry, fluid properties, well information or characteristics (e.g., geothermal gradient and pore pressure gradient, etc.) may be utilized by model  204  in conjunction with real-time sensor, meter, and/or gauge data acquired by gateway interface  208  and/or other devices and interfaces to determine the desired instantaneous annulus pressure. 
     It is to be understood that certain well characteristics and data that are utilized in model  204  may include relatively static values or parameters (e.g., generally static information about the well that may not change such as, but not limited to, well size). Other well characteristics and data may include dynamic values or parameters (e.g., real-time hole depth measurements). For example, in some implementations, the subterranean formation of the well may be a mature field, and therefore model  204  may include information regarding various known characteristics about a particular reservoir or reservoirs. For example, the ideal pressure at various depths of the subterranean formation may be known or calculated based on information and data from model  204 . 
     PRV set point control system  212  may be operatively coupled to and configured to control PRV assembly  110  of  FIG. 1 . For example, PRV assembly  110  may include a controller (e.g. an auxiliary programmable logic controller, remote input/output device, programmed computer, etc.) operatively coupled to the PRV set point control system  212  such that dynamic PRV set points may be provided in real-time to one or more pressure relief valves of the PRV assembly  110 . PRV set point control system  212  may access model  204  for determining the dynamic set points. 
     In this regard, PRV set point control system  212  may utilize model  204  and certain real-time sensor, meter, and/or gauge data acquired by gateway interface  208  and/or other devices and interfaces to determine a desired instantaneous set point for PRV assembly  110 . Similarly, PRV set point control system  212  may use model  204  and certain real-time sensor, meter, and/or gauge data to predict one or more future desired set points (e.g., a series of desired set points based on detected steady-state and/or changing conditions). 
     It is to be understood that, in accordance with aspects of the subject technology, determining dynamic set points is accomplished by PRV set point control system  212  in an automated process or processes. However, PRV set point control system  212  may be configured for user entry and input such that certain information and control may be afforded a user during the determination of the dynamic PRV set points and/or transmission to the PRV assembly  110 , for example. 
     Continuous circulation device control system  214  may be operatively coupled to and configured to control a continuous circulation device of rotary table and standpipe assembly  145 , for example, when a particular implementation of well system  100  includes such continuous circulation functionality. Continuous circulation device control system  214  can communicate with flow and pressure control system  202  so that drilling fluid  102  may be appropriately diverted and/or redirected during stages of the drill pipe connection process. 
     System  200  and network environment may also include other controllable electronic devices (e.g., gauges, flow meters, sensors, alarms, etc.) communicably connected to one or more computers or servers (e.g., flow and pressure control system  202 , PRV set point control system  212 , and/or continuous circulation device control system  214 ), such as by router  210  or other networking techniques. It is understood that in certain embodiments, each of flow and pressure control system  202 , PRV set point control system  212 , and continuous circulation device control system  214  may be a single computing device such as a computer server. In other embodiments, flow and pressure control system  202 , PRV set point control system  212 , and continuous circulation device control system  214  may represent more than one computing device working together to perform the actions of a server computer (e.g., a distributed system or sharing of certain data). Moreover, in some embodiments, each of flow and pressure control system  202 , PRV set point control system  212 , and continuous circulation device control system  214  may be operatively coupled with various databases or other computing devices that may be collocated with the well system  100 , or that may be disparately located. 
     PRV set point control system  212 , for example, may include one or more processing devices and one or more data storage devices. One or more processing devices may execute instructions stored in one or more data storage devices, which may store the computer instructions on non-transitory computer-readable medium. 
       FIG. 3  is flow diagram of an example method  300  for calculating and providing dynamic PRV set points. It is to be understood that the operations in method  300  may be used in conjunction with other methods/processes and aspects of the present disclosure described herein. Although certain aspects of method  300  are described with relation to the example embodiments provided in  FIGS. 1 and 2 , method  300  is not limited to such. 
     Method  300  may be used in conjunction with well system  100  and system  200  and network environment to control borehole (or bottom hole or wellbore) pressure during various well and drilling operations. In block  302 , PRV set point control system  212  may receive one or more input variables associated with one or more characteristics of well system  100 . The one or more input variables may be received or acquired during a time period, for example, 500 milliseconds, one second, 30 seconds, etc. The time period may change during the course of method  300  depending on the particular well or drilling operation, or stage thereof. Moreover, it is to be understood that certain input variables may be acquired at different time intervals or frequencies than other input variables, and such data acquisition time intervals may be different from the time period associated with receiving the one or more variables. 
     The one or more input variables and/or parameters) may include data from rig, platform, or other top-side equipment and/or bottom hole assembly (BHA) data. For example, the one or more input variables may include, but are not limited to, ‘bit depth’, ‘hole depth’, ‘stand pipe pressure’, ‘hookload’, ‘rotary speed’, ‘rotary torque’, ‘wellhead pressure’, ‘flow in’, ‘density in’, ‘temperature in’, ‘flow backpressure’, ‘BHA temperature,’ BHA pressure,′ and ‘BHA equivalent circulating density (ECD)’. 
     In accordance with certain aspects, ‘bit depth’ may be determined at a particular instance in time. For example, during the certain instances of drilling operation, the ‘bit depth’ and the ‘hole depth’ input variables may simultaneously increase and be the same. However, ‘bit depth’ may change as the drill bit  122  is retracted from the borehole  105  during some drilling operations, for example. ‘Bit depth’ and ‘hole depth’ input variables may be values in feet or meters. 
     ‘Stand pipe pressure’ may be measured and/or calculated in bars, PSI, or pascals. ‘Hookload’ may be measured and/or calculated in tons. ‘Rotary speed’ input variable relates to the rotary speed of drill string  120  and may be a value in revolutions per minute (RPM) or radians per second. ‘Rotary torque’ input value relates to the rotary torque of drill string  120 , and may be expressed in newton meters or foot pounds. ‘Wellhead pressure’ input variable relates to the actual pressure value of wellhead  125 , for example, as measured at choke manifold  160 , and may be expressed in bars, PSI, or pascals. 
     In certain aspects, ‘flow in’ input variable relates to a rate of flow of drilling fluid  102  into the borehole  105  from drilling fluid pumps, and can be measured by or derived from the drilling fluid pumps or a separate sensor or flow meter, for example. ‘Flow in’ input variable may be directly measured or calculated from other data, and may be expressed in liters per minute. ‘Density in’ input variable relates to a density of the drilling fluid  102  flowing into the borehole  105  from the rig or platform, and can be similarly measured by or derived from the drilling fluid pumps or a separate sensor or flow meter. Density of the drilling fluid  102  can be measured in kilograms per liter, for example. ‘Temperature in’ input variable relates to an instantaneous temperature of the drilling fluid  102  flowing into the borehole  105  from the rig or platform, and can be similarly measured by or derived from the drilling fluid pumps or a separate sensor or flow meter. 
     It is to be understood that, in some aspects, ‘flow in’, ‘density in’, and ‘temperature in’ input variables may relate to fluids other than drilling fluid  102 . For example, ‘flow in’, ‘density in’, and ‘temperature in’ input variables may relate to a cement composition that can be supplied by one or more cement pumps on the rig or platform. 
     In certain aspects, ‘flow backpressure’ input variable relates to the flow pressure added to the annulus  108  of borehole  105  by backpressure pump  180 , for example. In certain embodiments, backpressure pump  180  may provide a flow of drilling fluid  102  adequate such that the one or more chokes  166  can be maintained within an operable range during connection mode. As noted herein, in some embodiments, a pump diverter may be used to eliminate the need for backpressure pump  180 . Thus, in some aspects, ‘flow backpressure’ input variable can relate to the flow pressure added to the annulus  108  of borehole  105  by a pump diverter. 
     Additional non-limiting examples of input variables include ‘BHA temperature,’ BHA pressure,′ and ‘BHA ECD.’ For example, BHA temperature, pressure, and ECD can be acquired by and/or determined from measuring devices in the bottom hole assembly such as but not limited to one or more sensors  124  of drill string  120 . 
     In block  304 , PRV set point control system  212  may calculate a PRV set point. The PRV set point may be calculated based at least partially on model  204  and may utilize the one or more input variables. In this regard, model  204  of a well in well system  100  may utilize one or more of the various input variables and additional information (e.g., results from geological samples and data loggers) associated with the rig or platform equipment and subterranean formation, for example. Thus, model  204  can provide an instantaneous pressure profile of the well. For example, a range of pressure values including a high limit (e.g., fracture gradient) and low limit that the well can handle may be developed from model  204 . When ‘hole depth’ or ‘stand pipe pressure’ input variables change, for example, a resulting pressure profile of model  204  may likewise change. 
     Accordingly, model  204 , from which the pressure profile of the well and PRV set points may be calculated, is continuously changing throughout various well and drilling operations. For example, clay, sandstone, limestone formations encountered during the drilling process may substantially alter model  204  of the well. Thus, in certain aspects, PRV set point control system  212  is configured to dynamically calculate a plurality of PRV set points as the drill extends or retracts meter by meter within the reservoir and second by second based on the information in model  204  and the received one or more input variables. 
     For example, model  204  may utilize the following equation to calculate an instantaneous borehole or bottom hole pressure: BHP (bottom hole pressure)=hydrostatic pressure (e.g., drilling fluid weight)+ frictional pressure (ECD)+ backpressure (e.g., applied by choke manifold). This BHP equation and the various components thereof may be solved using the one or more input variables as updated by real-time sensor, meter, and/or gauge data in accordance with aspects of the present disclosure. 
     In some implementations, for example, some of the general guidelines or ranges associated with a given subterranean formation may be known based on historical data of the various input variables or parameters of the well. Additionally, during certain drilling operations, PRV set point control system  212  is configured to detect a condition in which the pressure profile is expected to be generally stable. As such the time period or intervals at which the one or more input variables are received and/or the PRV set points are calculated may be increased (e.g., less frequent calculation of dynamic PRV set points). In this regard, a limited number of input variables and/or parameters may be required to calculate dynamic PRV set points within an estimated range, for example, thereby limiting the processing burden on one or more processors of PRV set point control system  212 . 
     As shown in block  306 , the calculation of the PRV set point may include adding an offset value to the computed value for the PRV set point. For example, PRV set point control system  212  may provide an offset as a parameter to be used in computing or calculating the PRV set point. In some aspects, the offset parameter may be provided by a well operator based on known characteristics of the rig or platform equipment and subterranean formation. The offset parameter may be a static value for a specific implementation and added to the PRV set point as initially computed by the PRV set point control system  212 . In some embodiments, the offset parameter may be a variable and applied based on a determined mode of operation. For example, a first offset value may be used when the rig or platform is in drilling mode as determined by one or more input variables (e.g., based on a high threshold of rotary torque of the drill string  120 ), and a second offset value may be used when the rig or platform equipment is in connection mode as similarly determined by one or more input variables (e.g., based on a low threshold of rotary torque of the drill string  120 ). 
     In some embodiments, PRV set point control system  212  can distinguish between a drilling operation and a cementing operation based on at least partially the one or more input variables (e.g., based on ‘density in’). However, in other embodiments, a user may enter a parameter indicating that a cementing operation is being initiated. Accordingly, PRV set point control system  212  can provide different offset values for various operations associated with the well. 
     In block  308 , PRV set point control system  212  may determine whether the calculated PRV set point is valid. PRV set point control system  212  may base such a determination at least partially on a predetermined expected range of PRV set points for the well. For example, as noted herein, model  204  may include information regarding various known characteristics about a particular reservoir or reservoirs. As such, expected ranges of PRV set points for the well may be calculated by PRV set point control system  212 . 
     In some embodiments, a user may enter parameters into PRV set point control system  212  indicating the expected range of PRV set points for the well. Thus, the predetermined expected range of PRV set points can be the user-entered PRV set points or the user-entered PRV set points modified or adjusted by one or more characteristics associated with model  204  (e.g., factoring a known narrow pore-pressure-fracture-gradient window of the well at a specific hole depth) in accordance with various embodiments. If the calculated PRV set point is determined to be invalid, PRV set point control system  212  may determine whether an input variable value of one of the received one or more input variables is out of variance with a predetermined range of acceptable input variable values. For example, one or more of the input variable may include a range of acceptable values based on actual historical data, expected rages for the specific well system configuration, and/or user-entered parameters. 
     When a received input variable value is determined to be out of variance, PRV set point control system  212  may then recalculate the PRV set point based at least partially on model  204  utilizing a default value for the input variable, for example. In some embodiments, the default value may be the last received valid value for that particular input variable and a recalculation performed to determine the PRV set point (e.g., return to block  304 ). In other embodiments, a new value for the out of range input variable value may be attempted to be acquired. For example, the presently received one or more input variables may be disregarded, and PRV set point control system  212  may receive a new one or more input variables associated with one or more characteristics of well system  100  (e.g., return to block  302 ). 
     If the calculated PRV set point is determined to be invalid, PRV set point control system  212  may generate an alarm (block  310 ). The alarm generated by the presumed invalid PRV set point may be logged so that the incident may be reviewed at a later time to determine the cause of the presumed miscalculation (e.g., faulty telemetry or malfunctioning components), for example. 
     As shown in block  312 , if the calculated PRV set point is determined to be valid, PRV set point control system  212  may transmit the calculated PRV set point to a controller of PRV assembly  110 , for example. In this regard, PRV set point control system  212  can control the operation of and change the mechanical settings of one or more pressure relief valves. Next, as shown in block  314 , PRV set point control system  212  may monitor PRV assembly  110  to determine whether the calculated PRV set point is valid. For example, controller of PRV assembly  110  or other component can provide an indication to PRV set point control system  212  that at least one of the one or more of the pressure relief valves has tripped, activated, lifted or activated in some manner. When the calculated PRV set point is transmitted to the controller of PRV assembly  110  and at least one of the one or more of the pressure relief valves has been tripped, PRV set point control system  212  may generate a PRV trip alarm (block  316 ). 
     The PRV trip alarm generated by the presumed valid and calculated PRV set point may be logged along with other concurrent data points so that the PRV trip incident may be reviewed at a later time to determine the cause of the PRV trip incident (e.g., faulty telemetry, malfunctioning components, unexpected BHA temperature or pressure change, etc.). Additionally, in some embodiments, upon receiving a PRV trip alarm, PRV set point control system  212  may immediately recalculate or increase a frequency of calculating PRV set points (e.g., increase from a 10 second time interval to a 1 second time interval for calculating dynamic PRV set points). 
     Moreover, PRV set point control system  212  may log each of the calculated PRV set points that is transmitted to the controller of PRV assembly  110  (block  318 ), so that the PRV set points that did not result in a PRV trip incident can be later used for further analysis and historical data of the pressure profile of the well, for example. 
     Now referring to  FIGS. 4 and 5 , dynamic PRV set points are plotted with respect to time in accordance with various example drilling operations.  FIGS. 4 and 5  illustrate exemplary calculations of PRV set points in accordance with the method  300  of  FIG. 3  and other aspects of the present disclosure described herein. Accordingly, certain aspects of  FIGS. 4 and 5  are described with relation to the example embodiments provided in  FIGS. 1 and 2 . However, aspects of the present disclosure described in  FIGS. 4 and 5  are not limited to components and elements provided in the examples of  FIGS. 1 and 2 . 
       FIG. 4  provides a chart  400  that depicts dynamic PRV set points as plotted with respect to time. Chart  400  relates to an example of a drilling operation in which rotation of drill string  120  and a flow drilling fluid  102  through the borehole  105  is temporarily ceased when an additional drill pipe is added to drill string  120 . 
     Example RPM line  402  and example PRV set point line  404  show changes in respective values of the lines during various drilling operations. RPM line  402  (i.e., pump RPM) refers to the rotary speed of a crankshaft or piston of the one or more pumps (i.e., drilling fluid or cement pumps, depending on the application). By using the rotary speed of the crankshaft and other pump data such as displacement (e.g., stroke and bore) with other data associated with the pump in use, a flow rate of the fluid injected into borehole  105  may be calculated. In this regard, RPM line  402  may be representative of the ‘flow in’ input variable and correlated thereto. PRV set point control system  212  can use the pump RPM to calculate the various dynamic PRV set points, for example. PRV set point line  404  may be representative of calculated PRV set points by PRV set point control system  212 , in accordance with aspects of the present disclosure. As shown in chart  400 , during drilling mode  410  from time  0  to time t 1 , pump RPM may be at a steady-state value R 1 , thereby resulting in generally steady-state calculated PRV set point value P 1 . 
     During pump ramp down mode  420  from time t 1  to time t 2 , pump RPM may decrease in preparation for a drill pipe connection, in accordance with certain embodiments. As such, pump RPM may decrease from value R 1  to a zero (or near zero) value R 2 . Likewise, PRV set point control system  212  may calculate a series of steadily increasing PRV set point values from value P 1  to value P 2 . In certain examples, the rate of change between a series of consecutive PRV set points can be generally linear as illustrated in the example of  FIG. 4 . However, in other examples, the rate of change may be non-linear between a series of consecutive PRV set points. 
     In this regard, dynamically changing PRV set points during ramping down rotation of drill string  120  and/or stopping movement of the drill bit  122  longitudinally can provide precise pressure control in the borehole  105  during such transitional stages. In such instances, a higher pressure may be required in the borehole  105  to offset the frictional pressure caused by the drill bit  122  and/or the flow of drilling fluid  102  in order to support the subterranean formation. Accordingly, PRV set point control system  212  may calculate an associated higher PRV set point for the one or more pressure relief valves of the PRV assembly  110 . 
     Additionally, PRV set point control system  212  may be configured to detect that drilling operations have transitioned from drilling mode  410  to pump ramp down mode  420 . In this regard, PRV set point control system  212  can be configured to detect a condition reflecting a mode or stage for which frequent changing of PRV set points of the one or more pressure relief valves of PRV assembly  110  may aid in maintaining precise borehole pressure during certain changing conditions of well system  100 . As such the time period or intervals at which the one or more input variables are received and/or the PRV set points are calculated may be decreased (e.g., more frequent calculation of dynamic PRV set points). For example, PRV set point control system  212  may be configured to detect a threshold change in an input variable where the threshold change is triggered based on a particular value of the input variable or a particular increase/decrease in value of the input variable over a specific period of time. 
     During connection mode  430  from time t 2  to time t 3 , pump RPM may remain at zero (or near zero) value R 2 , thereby resulting in generally steady-state calculated PRV set point value P 2 . At this time, a new drill pipe may be added top-side to drill string  120  at top drive of rotary table and standpipe assembly  145 , for example. During pump restart mode  440  from time t 3  to time t 4 , drilling fluid pumps may begin activating and pump RPM may increase to a value slightly above R 2  (but significantly below R 1 ). The low RPM value at pump restart mode  440  enables urging of the drilling fluid (e.g., breaking gel strength) and helps to avoid pressure spikes upon restart. During pump restart mode  440 , the corresponding calculated PRV set points may remain at approximately value P 2 . 
     Still referring to  FIG. 4 , during pump ramp up mode  450  from time t 4  to time t 5 , pump RPM may increase as drilling operations move toward full speed with the new drill pipe connected to drill string  120 , in accordance with certain embodiments. As such, pump RPM may increase from zero (or near zero) value R 2  to value R 1 . Likewise, PRV set point control system  212  may calculate a series of steadily decreasing PRV set points from value P 2  to value P 1 . 
     In some embodiments, PRV set point control system  212  may be configured to determine a PRV set point trend line (e.g., a portion of PRV set point line  404 ) based at least partially on two or more previously calculated PRV set points. Thus, PRV set point control system  212  may calculate one or more additional PRV set points based at least partially on the determined PRV set point trend line. For example, PRV set point control system  212  may extrapolate a series of PRV set points toward a previously known value at value P 1 , thereby limiting the processing burden on one or more processors and/or interface frequency requirement with other systems/devices of PRV set point control system  212 . Similarly, a series of PRV set points may be extrapolated by PRV set point control system  212  when the PRV set point line  404  is generally flat (e.g., during drilling mode  410  and connection mode  430  scenarios). In certain embodiments and implementations, however, each calculated PRV set point may be based on real-time time sensor, meter, and/or gauge data. 
     At time t 5 , well system  100  may return to drilling mode  410 . As such, pump RPM may return to steady-state value R 1 , thereby resulting in generally steady-state calculated PRV set point value P 1 . It is to be understood that chart  400  is merely exemplary and illustrating a relationship between the pump RPM and calculated PRV set point values. However, the calculated PRV set points may factor in numerous input variables, and therefore may or may not generally resemble example PRV set point line  404  in various embodiments and implementations. 
       FIG. 5  is a chart  500  illustrating dynamic PRV set points plotted with respect to time. Chart  500  relates to an example of a continuous circulation drilling operation. For example, well system  100  may include a continuous circulation device as a component of rotary table and standpipe assembly  145  in the continuous circulation drilling operation example illustrated in  FIG. 5 . 
     Example RPM line  502  and example PRV set point line  504  show changes in respective values of the lines during various drilling operations. RPM line  502  (i.e., pump RPM) refers to the rotary speed of a crankshaft or piston of the one or more pumps (i.e., drilling fluid or cement pumps, depending on the application). By using the rotary speed of the crankshaft and other pump data such as displacement (e.g., stroke and bore) with other data associated with the pump in use, a flow rate of the fluid injected into borehole  105  may be calculated. In this regard, RPM line  502  may be representative of the ‘flow in’ input variable and correlated thereto. PRV set point line  504  may be representative of calculated PRV set points by PRV set point control system  212 , in accordance with aspects of the present disclosure. As shown in chart  500 , during drilling mode  510  from time  0  to time t 1 ′, pump RPM may be at a steady-state value R 1 ′, thereby resulting in generally steady-state calculated PRV set point value P 1 ′. 
     During pump ramp down mode  520  from time t 1 ′ to time t 2 ′, pump RPM may decrease in preparation for a drill pipe connection using a continuous circulation device, in accordance with certain embodiments. As such, pump RPM may decrease from value R 1 ′ to value R 2 ′, while drilling fluid  102  continues to circulate through borehole  105 . Likewise, PRV set point control system  212  may calculate a series of steadily increasing PRV set point values from value P 1 ′ to value P 2 ′. In certain examples, the rate of change between a series of consecutive PRV set points can be generally linear as illustrated in the example of  FIG. 5 . However, in other examples, the rate of change may be non-linear between a series of consecutive PRV set points. Moreover, as noted herein, PRV set point control system  212  may be configured to detect that drilling operations have transitioned from drilling mode  510  to pump ramp down mode  520  (or transitions from other modes or phases of operation). 
     During connection mode  530  from time t 2 ′ to time t 3 ′ in a continuous circulation drilling, pump RPM may remain at value R 2 ′, thereby resulting in generally steady-state calculated PRV set point value P 2 ′. At this stage, a new drill pipe may be added top-side to drill string  120  at continuous circulation device and top drive of rotary table and standpipe assembly  145 , for example. During pump ramp up mode  540  from time t 3 ′ to time t 4 ′, pump RPM may increase as drilling operations move toward full speed with the new drill pipe connected to drill string  120 , in accordance with certain embodiments. As such, pump RPM may increase from value R 2 ′ to value R 1 ′. Likewise, PRV set point control system  212  may calculate a series of steadily decreasing PRV set points from value P 2 ′ to value P 1 ′. 
     At time t 4 ′, well system  100  may return to drilling mode  510 . As such, pump RPM may return to steady-state value R 1 ′, thereby resulting in generally steady-state calculated PRV set point value P 1 ′. It is to be understood that chart  500  is merely exemplary and illustrating a relationship between the pump RPM and calculated PRV set point values. However, the calculated PRV set points may factor in numerous input variables, and therefore may or may not generally resemble example PRV set point line  504  in various embodiments and implementations. Moreover, it is to be understood that  FIGS. 4 and 5  are not drawn to scale, for example, a difference in the value between P 1 ′ and P 2 ′ of  FIG. 5  may be substantially less than a difference in the value between P 1  and P 2  of  FIG. 4   
       FIG. 6  conceptually illustrates a block diagram of an exemplary computer system  600  with which one or more aspects of the subject technology may be implemented, for example, PRV set point control system  212  and/or flow and pressure control system  202 . Computer system  600  can be a server and computer with one or more processors embedded therein or coupled thereto, or generally any computing device, and may include various types of computer readable media and interfaces for various other types of computer readable media. Computer system  600  may include, for example, a bus  608 , processing unit(s)  612 , a system memory  604 , a read-only memory (ROM)  610 , a permanent storage device  602 , an input device interface  614 , an output device interface  606 , and a network interface  616 . 
     Bus  608  collectively represents all system, peripheral, and chipset buses that communicatively connect the numerous internal devices of computer system  600 . For instance, bus  608  may communicatively connect processing unit(s)  612  with ROM  610 , system memory  604 , and permanent storage device  602 . 
     From these various memory units, processing unit(s)  612  may retrieve instructions to execute and data to process in order to execute the processes of the subject disclosure. The processing unit(s) can be a single processor or a multi-core processor in different implementations. 
     ROM  610  may store static data and instructions that are needed by processing unit(s)  612  and other modules of the computer system. Permanent storage device  602 , for example, may include a read-and-write memory device. This device can be a non-volatile memory unit that stores instructions and data even when computer system  600  is off. Some implementations of the subject disclosure may use a mass-storage device (such as but not limited to a magnetic or optical disk and its corresponding disk drive) as permanent storage device  602 . 
     Other implementations may use a removable storage device (such as but not limited to a floppy disk, flash drive, and its corresponding disk drive) as permanent storage device  602 . Like permanent storage device  602 , system memory  604  can be a read-and-write memory device. However, system memory  604  may be a volatile read-and-write memory, such a random access memory, in accordance with some implementations. System memory  604  may store some of the instructions and data that the processor(s) needs at runtime. In some implementations, the processes of the subject disclosure are stored in system memory  604 , permanent storage device  602 , or ROM  610 . For example, the various memory units may include instructions for associated with controlling PRV set points in accordance with some implementations of the subject technology. From these various memory units, processing unit(s)  612  may retrieve instructions to execute and data to process in order to execute the processes of some implementations. 
     Bus  608  may also connect to input and output device interfaces  614 ,  606 . Input device interface  614  enables a user to communicate information and select commands to the computer system. Input devices used with input device interface  614  include, for example, alphanumeric keyboards and pointing devices (also called “cursor control devices”). Output device interfaces  606  enables, for example, the display of images generated by the computer system  600 . Output devices used with output device interface  606  may include, for example, printers and display devices, such as but not limited to cathode ray tubes (CRT) or liquid crystal displays (LCD). Some implementations may include devices such as a touchscreen that can function as both input and output devices. 
     As shown in  FIG. 6 , bus  608  may also couple computer system  600  to a network (not shown) through a network interface  616 . In this manner, computer system  600  can be a part of a network of computers and/or various controllable electronic devices (e.g., the example system and network environment of  FIG. 2 ). The network may include, for example, a local area network (“LAN”), a wide area network (“WAN”), or an Intranet, or a network of networks. Any or all components of computer system  600  can be used in conjunction with various aspects of the subject disclosure. 
     The functions described above can be implemented in digital electronic circuitry, in computer software, firmware or hardware. In this regard, computer system  600  may be used to implement various illustrative blocks, modules, elements, components, methods, and techniques described herein. The techniques can be implemented using one or more computer program products. Programmable processors and computers can be included in or packaged as mobile devices. The processes and logic flows can be performed by one or more programmable processors and by one or more programmable logic circuitry. General and special purpose computing devices and storage devices can be interconnected through communication networks. 
     Some implementations may include electronic components, such as microprocessors, storage and memory that store computer program instructions in a machine-readable or computer-readable medium (alternatively referred to as computer-readable storage media, machine-readable media, or machine-readable storage media). Some examples of such computer-readable media may include RAM, ROM, read-only compact discs (CD-ROM), recordable compact discs (CD-R), rewritable compact discs (CD-RW), read-only digital versatile discs (e.g., DVD-ROM, dual-layer DVD-ROM), a variety of recordable/rewritable DVDs (e.g., DVD-RAM, DVD-RW, DVD+RW, etc.), flash memory (e.g., SD cards, mini-SD cards, micro-SD cards, etc.), magnetic or solid state hard drives, ultra density optical discs, any other optical or magnetic media, and floppy disks. The computer-readable media can store a computer program that is executable by at least one processors of processing unit(s)  612  and includes sets of instructions for performing various operations. Examples of computer programs or computer code include machine code, such as is produced by a compiler, and files including higher-level code that are executed by a computer, an electronic component, or a microprocessor using an interpreter. 
     For example, the instructions for performing various operations may be stored in the memory units and implemented in one or more computer program products, for example, one or more modules of computer program instructions encoded on a computer readable medium for execution by, or to control the operation of, the computer system  600 , and according to any method known to those of skill in the art, including, but not limited to, computer languages such as data-oriented languages (e.g., SQL, dBase), system languages (e.g., C, Objective-C, C++, Assembly), architectural languages (e.g., Java, .NET), and application languages (e.g., PHP, Ruby, Perl, Python). 
     Instructions for performing various operations may also be implemented in computer languages such as array languages, aspect-oriented languages, assembly languages, authoring languages, command line interface languages, compiled languages, concurrent languages, curly-bracket languages, dataflow languages, data-structured languages, declarative languages, esoteric languages, extension languages, fourth-generation languages, functional languages, interactive mode languages, interpreted languages, iterative languages, list-based languages, little languages, logic-based languages, machine languages, macro languages, metaprogramming languages, multiparadigm languages, numerical analysis, non-English-based languages, object-oriented class-based languages, object-oriented prototype-based languages, off-side rule languages, procedural languages, reflective languages, rule-based languages, scripting languages, stack-based languages, synchronous languages, syntax handling languages, visual languages, wirth languages, embeddable languages, and xml-based languages. Various memory units may also be used for storing temporary variable or other intermediate information during execution of instructions to be executed by processing unit(s)  612 . 
     While the above discussion primarily refers to microprocessor or multi-core processors that execute software, some implementations are performed by one or more integrated circuits, such as application specific integrated circuits (ASICs) or field programmable gate arrays (FPGAs). In some implementations, such integrated circuits execute instructions that are stored on the circuit itself. 
     As used in this specification and any claims of this application, the terms “computer”, “server”, “processor”, and “memory” all refer to electronic or other technological devices. These terms exclude people or groups of people. For the purposes of the specification, the terms “display” or “displaying” means displaying on an electronic or computer device. As used in this specification and any claims of this application, the terms “computer readable medium” and “computer readable media” are entirely restricted to tangible, physical objects that store information in a form that is readable by a computer. These terms exclude any wireless signals, wired download signals, and any other ephemeral signals. 
     It is understood that any specific order or hierarchy of blocks in the processes disclosed is an illustration of example approaches. Based upon design preferences, it is understood that the specific order or hierarchy of blocks in the processes may be rearranged, or that all illustrated blocks be performed. Some of the blocks may be performed simultaneously. For example, in certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the embodiments described above should not be understood as requiring such separation in all embodiments, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products. 
     Embodiments disclosed herein include: 
     A. A method comprising receiving, by one or more processors, one or more input variables associated with one or more characteristics of a well during a first time period, calculating a first pressure relief valve (PRV) set point based at least partially on a model of the well utilizing the one or more input variables received during the first time period, determining whether the first PRV set point is valid based at least partially on a predetermined expected range of PRV set points for the well; and transmitting the first PRV set point to a PRV controller when the first PRV set point is determined to be valid. 
     B. A system comprising one or more processors, and memory including instructions that, when executed by the one or more processors, cause the one or more processors to receive one or more input variables associated with one or more characteristics of a well, calculate one or more pressure relief valve (PRV) set points based at least partially on a model of the well utilizing the one or more received input variables, determine whether the one or more PRV set points are valid based at least partially on a predetermined expected range of PRV set points for the well, and transmit the one or more PRV set points to a PRV controller when the one or more PRV set points are determined to be valid. 
     C. A well system comprising a blowout preventer (BOP) stack, a choke manifold operatively coupled to the BOP stack, a pressure relief valve (PRV) operatively coupled to the choke manifold, a controller operatively coupled to the PRV, and a computer system that includes one or more processors and memory including instructions that, when executed by the one or more processors, cause the one or more processors to receive one or more input variables associated with one or more characteristics of the well system, calculate one or more PRV set points based at least partially on a model of the well system utilizing the one or more received input variables, determine whether the one or more PRV set points are valid based at least partially on a predetermined expected range of PRV set points for the well system, and transmit the one or more PRV set points to the controller for controlling the PRV when the one or more PRV set points are determined to be valid. 
     Each of embodiments A, B, and C may have one or more of the following additional elements in any combination: Element 1: wherein the one or more input variables associated with one or more characteristics of the well comprise at least one of a rotary speed of a drill string or a drilling fluid flow rate. Element 2: wherein the one or more input variables associated with one or more characteristics of the well comprise a pressure of a backpressure pump. Element 3: wherein calculating the first PRV set point comprises adding an offset value to a computed value for the first PRV set point. Element 4: wherein calculating the first PRV set point comprises determining a bottom hole pressure of the well. Element 5: wherein determining the bottom hole pressure comprises determining at least one of a hydrostatic pressure, a frictional pressure, and a backpressure. Element 6: further comprising determining, when the first PRV set point is determined to be invalid, whether an input variable value of one of the one or more input variables is out of variance with a predetermined range of acceptable input variable values corresponding to the one of the one or more input variables, recalculating, when the input variable value corresponding to the one of the one or more input variables is determined to be out of variance, the first PRV set point being based at least partially on the model of the well utilizing a default value for the one of the one or more input variables, and transmitting a recalculated first PRV set point to a PRV controller when the recalculated first PRV set point is determined to be valid. Element 7: further comprising receiving, by the one or more processors, one or more input variables associated with one or more characteristics of the well during a second time period different than the first time period, calculating a second PRV set point based at least partially on the model of the well utilizing the one or more input variables received during the second time period, determining whether the second PRV set point is valid based at least partially on the predetermined expected range of PRV set points for the well, and transmitting the second PRV set point to the PRV controller when the second PRV set point is determined to be valid. Element 8: further comprising determining a PRV set point trend line based at least partially on the first PRV set point and the second PRV set point, and calculating one or more additional PRV set points based at least partially on the PRV set point trend line. 
     Element 9: wherein the one or more input variables associated with one or more characteristics of the well comprise at least one of a drill bit depth within the well or a hole depth of the well. Element 10: wherein the one or more input variables associated with one or more characteristics of the well comprise at least one of a bottom hole assembly (BHA) temperature, a BHA pressure, and a BHA equivalent circulating density. Element 11: wherein the instructions that, when executed by the one or processors, cause the one or more processors to calculate the one or more PRV set points, further cause the one or more processors to calculate the one or more PRV set points at a first interval of time. Element 12: wherein the instructions that, when executed by the one or more processors, further cause the one or more processors to detect a threshold change in one of the one or more input variables, and determine whether a mode of drilling operation has changed based at least partially on the threshold change corresponding to the one of the one or more input variables. Element 13: wherein the instructions that, when executed by the one or processors, cause the one or more processors to calculate the one or more PRV set points at the first interval of time, further cause the one or more processors to change from calculating the one or more PRV set points at the first interval of time to calculating the one or more PRV set points at a second interval of time different from the first interval of time, when the one or more processors determine that the mode of drilling operation has changed. 
     Element 14: further comprising a backpressure pump operatively coupled to the choke manifold, wherein the one or more input variables comprise a flow rate of the backpressure pump. Element 15: further comprising one or more drilling fluid pumps, and a drilling fluid pump diverter operatively coupled to the one or more drilling pumps and to the choke manifold, the drilling pump diverter being configured to divert drilling fluid flow of the one or more drilling pumps to the choke manifold, wherein the one or more input variables comprise a flow rate of the one or more drilling fluid pumps. Element 16: further comprising one or more drilling fluid pumps, a drill string operatively coupled to the BOP stack, and a continuous circulation device operatively coupled to the drill string, the continuous circulation device being configured to provide continuous drilling fluid circulation by allowing the one or more drilling fluid pumps to stay active when a new drill pipe segment is being connected to the drill string. Element 17: further comprising a tubular assembly operatively coupled to the BOP stack, and one or more cement pumps operatively coupled to the tubular assembly, the one or more cement pumps being configured to inject a cement composition to the tubular assembly. 
     By way of non-limiting example, exemplary combinations applicable to A, B, and C include: Element 4 with Element 5; Element 11 with Element 12; and Element 12 with Element 13. 
     Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted. 
     As used herein, the phrase “at least one of” preceding a series of items, with the terms “and” or “or” to separate any of the items, modifies the list as a whole, rather than each member of the list (i.e., each item). The phrase “at least one of” allows a meaning that includes at least one of any one of the items, and/or at least one of any combination of the items, and/or at least one of each of the items. By way of example, the phrases “at least one of A, B, and C” or “at least one of A, B, or C” each refer to only A, only B, or only C; any combination of A, B, and C; and/or at least one of each of A, B, and C.