SAFE DYNAMIC TRANSFER BETWEEN MANAGED PRESSURE DRILLING AND WELL CONTROL

Abstract

A safe dynamic handover between MPD and well control operations provides the ability to automate MPD, well control, and the transitions between them while maintaining the wellbore in a fluid dynamic state at all times. In the event of a pressure hit, a safe dynamic handover from MPD to well control operations is performed, unknown formation fluids within the wellbore are circulated out of the wellbore, and a safe dynamic handover from well control operations to MPD is performed while maintaining the wellbore in a fluid dynamic state, never reaching a static state with respect to the fluids within the wellbore.Because the internal wellbore diameter remains in a dynamic state, gel formation is prevented, thus avoiding pressure spikes during mud pump startup and improving pressure transmission throughout the well system. Pressure can be managed more precisely during all phases of drilling, well control, and transitions between them.

Description

SAFE DYNAMIC TRANSFER BETWEEN MANAGED PRESSURE DRILLING AND WELL CONTROL CQzt? ιη / ζζηζ / Β / γίΛΐ BACKGROUND OF THE INVENTION Managed Pressure Drilling (MPD) techniques aim to manage pressure during drilling and other operations through the controlled application of surface backpressure. Typically, an annular seal system is used to controllably seal the annular space surrounding the drill string, and surface backpressure is applied controllably by manipulating the choke opening setting, sometimes called the choke position, of one or more choke valves in an MPD choke manifold located on the drilling rig. The MPD choke manifold is fluid-lined to one or more flow lines that divert return fluids from, or below, the annular seal to the surface.Each throttle valve is capable of reaching a fully open state where flow is unimpeded, a fully closed state where flow is stopped, and a number of intermediate states where flow is at least partially restricted. In this way, if the pressure in the annulus falls below a lower threshold, one or more throttle valves in the MPD throttle manifold can be closed as needed to increase the annulus pressure by the required amount. Similarly, if the pressure in the annulus rises above an upper threshold, one or more throttle valves in the MPD throttle manifold can be opened as needed to decrease the annulus pressure by the required amount. In practice, MPD systems are used in one of several operating modes.In surface backpressure mode, the surface backpressure in the MPD choke manifold is managed directly. In downhole pressure mode, a hydraulic model is used to calculate a pressure that will achieve a desired pressure at depth based on models, real-time data, and the operation being performed. Regardless of the operating mode, the pressure is managed by manipulating one or more choke valves in the MPD choke manifold. During certain drilling operations, MPD can be used to maintain well control by managing the wellbore pressure within a safe pressure gradient bounded by the pore pressure and fracture pressure. Sometimes, the collapse pressure is used instead of the pore pressure if it is higher. In this context, well control generally refers to techniques used to manage hydrostatic and formation pressure to prevent the unintentional influx of unknown formation fluids into the well system. If the pressure in the annulus falls below the pore pressure, unknown formation fluids can flow into the wellbore, and well control can be lost. The unintentional influx of unknown formation fluids into the wellbore is commonly referred to as a pressure hit.Pressure shocks are inherently dangerous because unknown formation fluids may contain explosive gas, increasing the risk of a dangerous blowout. Similarly, if the pressure in the annulus rises above the fracture pressure, the formation can fracture or crack hydraulically, resulting in the loss of drilling fluids into the formation. If the fluid level within the wellbore drops to the point where the wellbore pressure falls below the pore pressure, a pressure shock can occur, and well control can be lost. Therefore, conventional industry practices aim to maintain well control during drilling and other operations by carefully traversing the safe pressure gradient.However, geological uncertainties, imperfect information, and constantly changing conditions sometimes lead to unexpected contingencies, and it is vital to be able to take appropriate action when a pressure hit occurs. In this regard, once a pressure hit has occurred, if the volume of the pressure hit and the additional pressure required to kill the well exceed a predetermined operating limit, MPD operations are stopped, and well control operations are performed manually to circulate out the unknown formation fluids in the well system to re-establish well control so that drilling operations can be safely resumed. BRIEF SUMMARY OF THE INVENTION According to one aspect of one or more embodiments of the present invention, a method for safe dynamic handover between managed pressure drilling and well control includes setting a pressure setpoint of an MPD choke manifold to a surface backpressure setpoint and setting a pressure setpoint of an automated well control choke manifold to a sensed pressure taken from below a blowout preventer or a choke line pressure of the blowout preventer. A pressure imbalance is created by setting the pressure setpoint of the MPD choke manifold above the pressure setpoint of the automated well control choke manifold by a predetermined amount.Pressure imbalance automatically causes an MPD control system to close the MPD choke manifold when the well control system opens the automated well control choke manifold. The method also includes verifying that the detected pressure or the pressure of The choke line is increased until the automated well control choke manifold opens sufficiently so that the blowout preventer (BOP) pressure or the choke line pressure remains constant. A BOP annulus is then closed after the MPD choke manifold has been closed, and unknown formation fluids are diverted from the BOP choke line to the automated well control choke manifold for delivery to a mud and gas separator. The wellbore remains in a fluid dynamic state due to the continuous injection of drilling fluids. According to one aspect of one or more embodiments of the present invention, a non-transient, computer-readable means comprising software instructions that, when executed by a processor, perform a safe dynamic handover method between managed pressure drilling and well control, including setting a pressure setpoint of an MPD choke manifold to a surface backpressure setpoint and setting a pressure setpoint of an automated well control choke manifold to a sensed pressure taken from below a blowout preventer unit or a choke line pressure of the blowout preventer unit. A pressure imbalance is created by setting the pressure setpoint of the MPD choke manifold above the pressure setpoint of the automated well control choke manifold by a predetermined amount.Pressure imbalance automatically causes an MPD control system to close the MPD choke manifold when the well control system opens the automated well control choke manifold. The method further includes verifying that the sensed pressure or choke line pressure increases until the automated well control choke manifold opens sufficiently so that the blowout preventer (BFP) pressure or choke line pressure remains constant, closing a BFP annulus after the MPD choke manifold has closed, and diverting unknown formation fluids from the BFP choke line to the automated well control choke manifold for delivery to a mud-gas separator.The internal diameter of the well remains in a fluid dynamic state due to the continuous injection of drilling fluids. According to one aspect of one or more embodiments of the present invention, a system for a safe dynamic handover between managed pressure drilling and well control includes an annular sealing system capable of controllably sealing an annular space surrounding a drill string forming an MPD annular seal, and a blowout prevention unit capable of controllably sealing a space CQzt? ιη / ζζηζ / Β / γίΛΐ annular surrounding the drill string forming a well control annular seal, an MPD choke manifold comprising a plurality of choke valves with at least one choke valve in fluid communication with a flow line capable of diverting return fluids from or below the MPD annular seal to a fluid processing system, an automated well control choke manifold comprising a plurality of choke valves with at least one choke valve in fluid communication with a choke line capable of diverting return fluids from or below the well control annular seal to a mud and gas separator,and a well control system that automates the adjustments of the automated well control choke manifold during handovers between pressure-managed drilling and well control operations to maintain the wellbore's internal diameter in a fluid dynamic state. Other aspects of the present invention will be evident from the following description and claims. BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 shows a conventional closed-loop hydraulic drilling system for conventional pressure managed drilling and well control operations. Figure 2 shows an improved closed-loop hydraulic drilling system for a safe dynamic handover between pressure-managed drilling and well control according to one or more embodiments of the present invention. Figure 3 shows an illustrative control system according to one or more embodiments of the present invention. DETAILED DESCRIPTION OF THE INVENTION One or more embodiments of the present invention are described in detail with reference to the accompanying figures. For consistency, similar elements in the various figures are indicated by similar reference numbers. In the following detailed description of the present invention, specific details are set forth to provide a complete understanding of the present invention. In other cases, to avoid obscuring the description of the present invention, features well known to a person skilled in the art are not described.For the purposes of clarity, for the wellbore internal diameter components described herein, top or upper part refers to a portion or side that is closest, either directly or in reference to another component, to the surface above the wellbore internal diameter, and bottom or lower part refers to a portion or side that is closest, either directly or in reference to another component, to the bottom of the wellbore internal diameter. CQzt? Ln / zznz / e / γΐΛΐ Figure 1 shows a conventional closed-loop hydraulic drilling system 100 for conventional MPD and well control operations. For illustrative purposes, a drilling system 100 for offshore drilling operations is shown. Although offshore applications require additional components, such as a marine riser system, to facilitate drilling a subsea wellbore internal diameter, a person skilled in the art will recognize that onshore or land-based applications are substantially similar in configuration and function with respect to the components required for conventional MPD and well control operations. In this respect, the description that follows applies equally to land-based drilling systems that include MPD and conventional well control capabilities. Drilling system 100 includes a drilling rig 101, in this case, a semi-submersible drilling rig positioned in a body of water 102, which includes various equipment configured to drill an internal diameter of a subsea well 106 below the seafloor 104 to recover hydrocarbons located therein. A person skilled in the art will appreciate that the type or class of drilling rig may vary based on the application. In deepwater applications, the seafloor 104 may be more than 1,000 feet below the water surface 102. In ultra-deepwater applications, the seafloor 104 may be 5,000 feet or more below the water surface 102.Drilling system 100 may include an MPD system (e.g., the annular sealing system 110, the annular closing system 115, and the return reel 120), a marine riser system 125, and a blowout preventer (BOP) unit 130; in the marine example shown, a subsea BOP (SSBOP). A person skilled in the art will recognize that drilling system 100 may include other components such as, for example, a last-resort diverter (not shown), a ball joint (not shown), and a telescoping joint (not shown), which are typically positioned above the MPD system and are neither shown nor necessary for understanding the analysis that follows. For high-specification drilling systems 100, the MPD system typically includes an annular sealing system 110, an annular shut-off system 115 disposed below the annular sealing system 110, and a return flow spool 120 disposed below the annular shut-off system 115. The annular sealing system 110 controllably seals the annular space 108 surrounding the drill string 135, thereby encapsulating it. The annular sealing system 110 may be a Rotary Control Device (RCD), an Active Control Device (ACD), or any other type or class of system capable of creating an annular seal such that the wellbore internal diameter pressure can be controlled by applying backpressure. CQzt? ιη / ζζηζ / Β / γίΛΐ surface. The annular seal system 115 is a redundant system for maintaining the annular seal when the annular seal system 110, or components thereof, are being installed, serviced, or replaced. The return flow spool 120 diverts return fluids from or below the annular seal to the MPD choke manifold 145, which directs the return fluids to fluid processing systems (e.g., the MGS 155 or vibrating screens 160) for recycling and reuse. The return flow spool 120 is located above, and in fluid communication with, the lower portion of the marine riser system 125.An expert in the field will recognize that, in lower specification drilling systems, one or more of the components mentioned above may be combined or excluded, but all MPD systems require at least an annular seal system disposed above the BOP 130 and means for controllably diverting return fluids from or below the annular seal. The lower portion of the marine riser system 125 is disposed above, and in fluid communication with, the SSBOP 130 disposed on or near the seabed 104. The SSBOP 130 may include a lower marine riser package (LMRP) connector (not labeled), an upper annular preventer unit 126, a lower annular preventer unit 127, one or more blind shear rams 128, one or more casing shear rams 129, an upper variable inside diameter ram 131, a lower variable inside diameter ram 132, and a wellhead connector (not labeled). The choke line 124 connects with fluid connection one or more mud pumps (e.g., 170) arranged on the surface to the SSBOP 130 to inject fluids below the annulus of the SSBOP 130 during conventional well control operations described in more detail herein.Choke line 133 connects, via fluid connection, an outlet of SSBOP 130 below the annulus to a well control choke manifold 134 located at the surface to carry fluid returns through choke line 133 during conventional well control operations, also described in more detail herein. SSBOP 130 is located above, and in fluid communication with, a wellhead (not separately illustrated) which is located above, and in fluid communication with, a borehole diameter 106 being drilled.A central light extends through the conventional MPD system (e.g., the annular sealing system 110, the annular closing system 115, and the return spool 120), the marine riser system 125, the SSBOP 130, the wellhead (not shown separately), and into the inside of the wellbore bore 106 to facilitate drilling and other operations. The drill string 135 can be laid through the central light and include, in a... CQzt? ιη / ζζηζ / Β / γίΛΐ distal end, a bottom hole assembly or drill bit 140 configured to drill the internal diameter of well 106. During MPD operations, such as forward drilling, one or more mud pumps 170 controllably pump drilling fluids (not shown) from the mud tank 165 to the bottom of the well through an internal passage of the drill string 135. Return fluids (not shown) return through the annular space 108 surrounding the drill string 135 and are controllably diverted by the return flow spool 120 through the flow line 122 to one or more choke valves (not separately illustrated) of the MPD choke manifold 145.One or more throttling valves of the MPD 145 throttling manifold allow controllable flow through flow line 147 to flow meter 150, and flow meter 150 then flows through flow line 153 to one or more fluid processing systems, including, for example, the MGS 155 and / or vibrating screens 160, for processing before returning the processed fluids (not shown) to the mud tank 165 for reuse. One or more pressure sensors (not shown) are arranged in the fluid path at various locations to measure the pressure of the return fluids (not shown). The MPD 190 control system can receive pressure sensor data and flow meter 150 data in approximately real-time or near real-time. A person skilled in the art will recognize that approximately real-time or near real-time means very close to real-time when measured, delayed only by measurement, calculation, and / or transmission, but typically on the order of magnitude of mere fractions of a second or seconds. The MPD 190 control system can direct one or more throttle valves (not separately illustrated) of the MPD 145 throttle manifold to a desired throttling position and / or direct the flow of the 170 mud pumps to achieve the desired pressure.The pressure-tight seal in the annular space provided by the 110 annular sealing system allows for precise control of wellbore pressure by manipulating the choke position of one or more choke valves (not individually illustrated) of the MPD 145 choke manifold and applying a corresponding surface backpressure. The choke position of one or more choke valves (not individually illustrated) of the MPD 145 choke manifold corresponds to a quantity, usually represented as a percentage, to which one or more choke valves (not individually illustrated), or the MPD 145 choke manifold itself, are open and capable of flow.If the choke operator wishes to increase the wellbore internal diameter pressure, the choke position of one or more choke valves (not independently illustrated) of the MPD 145 choke manifold can be reduced. CQzt? ιη / ζζηζ / Β / γίΛΐ further restrict fluid flow and apply additional surface backpressure. Similarly, if the choke operator wishes to decrease the borehole pressure, the choke position of one or more choke valves (not independently illustrated) of the MPD 145 choke manifold can be increased to increase fluid flow and reduce the amount of surface backpressure applied. In this respect, MPD systems typically manage borehole pressure by manipulating the choke position of one or more choke valves (not independently illustrated) of the MPD 145 choke manifold and / or the flow rate of the mud pumps 170 that inject fluids downhole, based on at least pressure sensor data. In certain applications, a hydraulic model (not shown separately) can be used during MPD and other operations to calculate wellbore internal diameter pressure, or equivalent circulating density (ECD), in approximately real-time or near real-time based on information about wellbore internal diameter, equipment, and sensor data, including, but not limited to, one or more of wellbore depth, casing depth, inside diameter, inclination angles, water depth, riser diameter, drill string configuration, geothermal gradient, hydrothermal gradient, real-time drilling parameters such as flow rate, rotation rate, block position (or drill bit depth), block velocity, and mud properties, and surface- or downhole-based sensor data that provide actual measurements of various parameters in approximately real-time or near real-time.The ECD refers to the effective density exerted by a circulating fluid against the formation, taking into account the pressure drop in the annulus above the point under consideration. Thus, the ECD can be thought of as the wellbore pressure expressed in terms of mud weight equivalent at a given depth. During drilling operations, the ECD is generally preferred over the wellbore pressure because it is more descriptive for those operating the drilling rig. However, a knowledgeable person will recognize that these are alternative representations of the same concept and can be used interchangeably with a simple conversion. The MPD system can be operated in one of several modes.During drilling and other operations, the MPD system can be used to perform what is called surface backpressure control. In this operating mode, the throttle position of one or more throttle valves on the MPD 145 choke manifold can be adjusted, either directly or automatically, to achieve a desired pressure in the MPD 145 choke manifold at the surface. However, the... The MPD system can also be used to manage downhole pressure. In this operating mode, the hydraulic model can be used to calculate the pressure, and the MPD 190 control system's programmable logic controller (PLC) can determine the choke position of one or more choke valves in the MPD 145 choke manifold to achieve the calculated downhole pressure at depth, taking into account the specific characteristics of the well's internal diameter, equipment, and sensor data. As mentioned previously, during conventional DPM operations, drilling fluids are pumped through the inside passage of drill string 135, out of drill bit 140, and then return through the annular space 108. The drilling fluids cool and lubricate drill bit 140, sweep drill cuttings from the bottom of the hole, and counteract formation pressure. The return fluids are typically processed at the surface, and the drilling fluids are separated and recycled for reuse downhole. As long as the wellbore pressure is effectively managed, under normal operating conditions, the outflow of return fluids is substantially equal to the inflow of drilling fluids.In this respect, there is no substantial loss of drilling fluids to the formation, and there is no substantial influx of unknown formation fluids into the wellbore. However, due to geological uncertainties, pressure shocks are sometimes experienced while drilling forward. Pressure shocks can be identified, for example, by an imbalance where the outflow exceeds the inflow for a period of time. When a pressure shock is detected while drilling forward, the MPD system is the first piece of equipment used to respond. Upon detecting a pressure shock, the MPD control system will begin closing the MPD 145 choke manifold to apply additional pressure to the wellbore in order to inhibit the formation of pressure shocks, sometimes referred to as killing the well.Once the wellbore internal diameter pressure equals or exceeds the pore pressure, the outflow should return to expected levels. When the outflow is substantially equal to the inflow, a determination is made as to whether the volume of formation fluids taken during the pressure hit requires well control operations. The driller will typically place the total pressure hit volume, along with the additional pressure required to equilibrate the formation, into an operational matrix that determines whether the inflow can be circulated out of the well through the MPD system. If the total pressure hit volume exceeds the operational matrix, regulations, equipment limitations, or agreed-upon limits on what can be circulated through the MPD system, then a decision is made to invoke manual well control operations to circulate the pressure hit. CQzt? ιη / ζζηζ / Β / γίΛΐ outlet through the well control choke manifold 134 under a closed BOP 130. It is important to recognize that MPD operations are sometimes carried out in an automated mode and the determination to invoke well control operations requires the intervention of a human operator to make the decision to invoke, as well as to manually perform the following well control operations. Once the decision has been made to circulate the pressure surge to the outside through manual well control operations, a first transition, or handover, from MPD operations to conventional well control operations is performed. Mud pumps 170 are shut down, drill string rotation 135 is stopped, and MPD choke manifold 145 is closed to maintain bottomhole pressure, resulting in the first static state with respect to the fluids within the wellbore 106, meaning there is no fluid circulation in the wellbore during this time. This is the first of two times the wellbore reaches a static state during handovers.Then, BOP 130 is closed, via annular 126 or 127 or ram 128, 129, 131, or 132, and choke line 133 is pressed down against the Hydraulically Controlled Remote (HCR) valve (not shown) of BOP 130, which then opens, allowing returns to be taken through choke line 133. Mud pumps 170 are then restarted and sped up to begin injecting drilling fluids down drill string 135, while the choke position of the well control choke manifold 134 is manually adjusted in an attempt to regulate bottomhole pressure while returns are taken through choke line 133, based on pressure measurements taken at the well control choke manifold. 134 or in the BOP 130.Bottomhole pressure regulation is manually controlled, typically by a choke operator who adjusts the choke position of the well control choke manifold 134 until the pressure in the choke line 124, as measured at the surface, or the pressure in the BOP 130, as measured underwater by a sensor (not shown), is constant. A person skilled in the art will appreciate that measuring the pressure in the BOP 130 is preferred; however, in systems without such a sensor (not shown), the choke line pressure 124 may be used. The choke operator turns a physical handwheel or, in electronically controlled choke manifolds, manually presses an up or down position button on an industrial control system (not shown) while monitoring the choke line pressure 124 or BOP 130 to ensure stability. After setting the desired speed of the 170 mud pump, the throttling operator manipulates the throttling position of one or more valves of the CQzt? ιη / ζζηζ / Β / γίΛΐ well control choke manifold 134, maintaining constant riser pressure, until the pressure shock has been circulated out of wellbore 106. The density of the return fluids is continuously measured at the surface. As long as the density of the return fluids is substantially equal to the density of the injected fluids (i.e., meaning no explosive gases remain in the return fluids), the pressure shock volume has been circulated out of wellbore 106 and the well control operation is complete. At this point, a second handover is performed, this time from well control operations to MPD, so that the MPD system can resume forward drilling.Mud pumps 170 are shut down again, and well control choke manifold 134 is closed when mud pumps 170 shut down, such that when mud pumps 170 stop completely, well control choke manifold 134 is fully closed. This represents the second static state with respect to the fluids within the wellbore internal diameter 106, because circulation has stopped. The bottomhole pressure is maintained at a constant pressure in the choke line 124 or below the BOP seal 130 while mud pumps 170 are decelerating. The marine riser 125 is then pressurized to equalize the pressure along the BOP 130, then the BOP 130 is opened. The HCR valve (not separately illustrated) is closed after the mud pumps 170 have stopped or after the pressure has equalized along the BOP 130, at the driller's discretion.Circulation is then restored by starting mud pumps 170, injecting drilling fluids that run down drill string 135 and bringing returns through flow line 122 from return flow reel 120. MPD choke manifold 145 is then reactivated to manage wellbore internal diameter pressure 106 during drilling operations, usually in automated mode. Although MPD operations are typically automated—meaning the hydraulic model is used to calculate the desired pressure and the MPD 190 control system determines the appropriate choke position of one or more choke valves on the MPD 145 choke manifold to achieve the desired pressure—conventional well control operations are performed manually, including the decision to invoke well control operations. During the initial handover from MPD to conventional well control operations, the mud pumps 170 are stopped, and the wellbore 106 reaches a fluid static state below the BOP 130 for the first time. During the critical portion of well control operations, the pressure stroke volume is manually circulated out of the wellbore 106.Again, during the second handover, from conventional well control operations to MPD, the 170 mud pumps were. CQzt? ιη / ζζηζ / Β / γίΛΐ stops and the internal diameter of well 106 reaches a fluid static state for the second time. In both cases, the fluid static state of the internal diameter of well leads to the formation of gels. When the fluids within the internal diameter of well 106 reach a static state, there are solids in the fluid mixture of the internal diameter of well and these solids react, creating what are known in the industry as gels. Gels are undesirable because they tend to create pressure spikes during the startup of mud pumps 170, in addition to creating difficulties in the transmission of pressure through the well system as required for the accurate management of pressure inside the wellbore 106. Therefore, whenever circulation stops and the wellbore 106 reaches a static state, gels form and additional force must be applied to break the gel reaction and reduce friction. Consequently, in one or more embodiments of the present invention, a safe dynamic handover between MPD and well control operations is achieved, for the first time. The ability to automate MPD, well control operations, and the transitions between them is also provided, maintaining the wellbore in a fluid dynamic state at all times, thus increasing the reliability, efficiency, and safety of operations. In the event of a pressure surge, a safe handover from MPD to well control operations is performed without ever reaching a static state with respect to the fluids within the wellbore. Unknown formation fluids within the wellbore are circulated out of the wellbore in a safe and efficient manner. A safe handover from well control operations to MPD is also performed without ever reaching a static state with respect to the fluids within the wellbore.Advantageously, because the internal wellbore diameter remains in a dynamic state, even during transfers, gel formation is avoided, thus preventing pressure spikes during mud pump startup. Furthermore, pressure transmission is improved, allowing for more precise pressure management during all phases of MPD operations, well control operations, and transitions between them. Figure 2 shows an improved closed-loop hydraulic drilling system 200 with an automated well control choke manifold 234 for a safe dynamic handover between MPD and well control operations according to one or more embodiments of the present invention. Dynamic handover means a transfer or transition between MPD and well control or between well control and MPD where the wellbore's internal diameter remains in a fluid dynamic state due to the continuous injection of drilling fluids. For illustrative purposes, a drilling system 200 for offshore drilling operations is shown. Although offshore applications require additional components such as, for example, a tubing system. CQzt? Ln / zznz / e / YiAi desired choke to achieve a desired surface pressure or wellbore pressure. Assuming, for analysis purposes, that the drilling system 200 is drilling forward using the MPD system (e.g., the annular sealing system 110, the annular closing system 115, and the return spool 120), potentially in automated mode. Due to geological uncertainties, a pressure hammer may be experienced unexpectedly. When a pressure hammer is detected, the MPD system may be the first equipment used to respond to the contingency. Upon detection of a pressure hammer, the MPD control system may begin closing one or more choke valves in the MPD choke manifold 145 to apply additional pressure in the wellbore in order to inhibit the formation of pressure hammers.For example, under automated operation, the MPD 190 control system can begin closing one or more choke valves on the MPD 145 choke manifold until the outflow is substantially equal to the inflow. Once the wellbore pressure equals or exceeds the pore pressure, the outflow should return to expected levels. When the outflow is substantially equal to the inflow, a determination can be made as to whether the volume of unknown formation fluids taken during the pressure hit requires well control operations. The driller will typically place the total pressure hit volume, along with the additional pressure required to balance the formation, into an operational matrix to determine if the unknown formation fluids can be circulated out of the well through the MPD system.If the total pressure stroke volume exceeds the operating matrix, regulations, equipment technical limitations, or agreed limits on what can be circulated through the MPD system, then a decision is made to invoke well control operations. In certain embodiments, a Dynamic Formation Integrity Test (DFIT) can be performed to determine the maximum mud pump speed that can be used to circulate the unknown formation fluid volume within the wellbore's internal diameter 106. In this way, the MPD system can be used to apply additional surface backpressure to the wellbore while the mud pumps 170 are operating. The inflow and outflow can be monitored to identify if well 106 begins to incur losses such that the inflow exceeds the outflow. The result of the DFIT is a determination of the pressure range that the formation maintains intact. The higher the pressure, the higher the mud pump 170 speed that can be used, provided that the choke line friction 133 is not exceeded while doing so.In an ideal situation, the preference is to fully open the fluid path through the manifold. CQzt? Ln / zznz / e / γΐΛΐ automated well control choke 234 to shorten the time required to circulate the pressure stroke volume. At this point, the pressure surge was experienced. It was determined that the surge should be circulated out using well control operations, and the MPD system was used to kill the well. The MPD system is in bottomhole pressure mode, where the hydraulic model is used to calculate the bottomhole pressure. With this information, the choke PLC (not separately illustrated) of the MPD 190 control system determines whether it is necessary to increase or decrease the pressure setpoint of the MPD 145 choke manifold at the surface to achieve the desired bottomhole pressure, thereby regulating the bottomhole pressure by applying a surface backpressure.The rotation of the drill string can be stopped or significantly reduced. The drill string can then be spaced out, such that drill string 135 is moved up or down, usually up, because drill bit 140 is likely at the bottom of hole 106 when drilling forwards. This ensures that no pipe splices are in the path of the blind shear rams 128 or the pipe rams 129, 131, and 132. Then, the rotation of drill string 135 and the booster are stopped. The real-time hydraulic model can calculate the friction loss in well 106, and because the MPD system is in downhole pressure mode, the MPD control system 190 can automatically adjust the choke position of one or more choke valves in the MPD choke manifold 145 to compensate for the change.The drilling fluid injection rate can be reduced to the maximum flow rate for the automated well control choke manifold 234. If the DFIT indicates sufficient flow is possible, it may be possible to leave the Pressure While Drilling (PWD) tool active. This can be simulated beforehand using advance simulations to define the friction contribution of the choke line 133 with sufficient flow to keep the PWD tool active. At this point, the MPD system may be regulating to the surface pressure. With the automated well control choke manifold 234 fully closed at this point, the HCR valve (not shown separately) can be opened, which can be verified by a pressure increase in the choke lines 124 and 133.Although differences in pressures in choke lines 124 and choke line 133 may be expected due to possible differences in mud weight and temperature between marine riser 125 and lines 124 and 133, the differences should be meaningful and of the same order of magnitude. At this point, returns could potentially be brought through both the MPD 145 choke manifold and the well control choke manifold. The automated well control choke manifold 234 is regulating to a sensed pressure taken from below the BOP 130 or the choke line pressure 124. However, conventional industry practice is to isolate the marine riser 125 from the wellbore 106 for safety reasons. In order to automatically begin closing the MPD choke manifold 145 when the automated well control choke manifold 234 opens, a small pressure imbalance is created between the MPD choke manifold 145 and the automated well control choke manifold 234, causing the MPD control system 190 to automatically close one or more valves in the MPD choke manifold 145.For example, the MPD 190 control system can set the MPD 145 choke manifold pressure setpoint to a value higher than the Automated Well Control 234 choke manifold pressure setpoint by a predetermined amount, such as 50 pounds per square inch (psi). A person skilled in the art will recognize that the predetermined amount can vary based on the application or design. Then, verify that the sensed pressure taken from below the BOP 130 or the choke line 124 increases until the Automated Well Control 234 choke manifold begins to open as needed to maintain a constant pressure at the BOP 130 or choke line 124.For example, the 290 well control control system begins to open the 234 automated well control choke manifold as needed to maintain constant pressure in the 130 BOP or the 124 choke line. The 150 MPD flow meter will likely see a loss, while the optional 250 well control flow meter, if included, will show a substantially equivalent gain. When the MPD 145 choke manifold is fully closed, all returns from the wellbore 106 can flow through the automated well control choke manifold 234. At this point, the BOP 130 can be closed, either through the annulus 126 or 127 or the ram 128, 129, 131, or 132. Return fluids can be routed from the BOP 130 choke line 133 to the automated well control choke manifold 234 for delivery to the mud and gas separator 155.Advantageously, the entire process, including forward drilling with MPD, detecting the pressure hit, handing off from the MPD system to well control, and performing well control operations, is done with the wellbore's internal diameter remaining in a fluid dynamic state below the BOP 130, with consistent fluid injection. With the marine riser 125 isolated, the MPD control system 190 can monitor for potential gas within the riser 125, and if gas is present, it can be circulated using the MPD system. cozb Ln / zznz / e / YiAi Similarly, once well control operations are complete, the handover from well control operations to the MPD system can be performed without ever reaching a static state with respect to the wellbore fluids. To transition from well control operations to MPD, the MPD choke manifold 145 can be used to pressurize the marine riser 125 to equalize the pressure along the BOP 130. Once equalized, the BOP 130 can be opened, and the automated well control choke manifold 234 can be operated in a mode that seeks to manage the pressure in the BOP 130.In order to automatically begin closing the automated well control choke manifold 234 when the MPD choke manifold 145 opens, a small pressure imbalance can be created between the automated well control choke manifold 234 and the MPD choke manifold 145. For example, the well control control system 290 can set the pressure setpoint of the automated well control choke manifold 234 to a value higher than the pressure setpoint of the MPD choke manifold 145 by a predetermined amount, such as 50 psi. A person skilled in the art will recognize that the predetermined amount can vary based on the application or design.Then, it is verified that the sensed pressure taken from below the annular closure system 110 increases until the MPD 145 choke manifold begins to open as needed to maintain constant pressure below the annular closure system 110. For example, the MPD 190 control system begins to open the MPD 145 choke manifold as needed to maintain constant pressure below the annular closure system 110. The optional well control flow meter 250, if present, will show a loss while the MPD 150 flow meter will show an equivalent gain during the transition, whereby the well control choke manifold 234 closes as the MPD 145 choke manifold opens.When the automated well control choke manifold 234 is fully closed, the HCR valve (not independently lubricated) can be closed and all returns from wellbore 106 can flow through the MPD choke manifold 145. At this point, MPD operations, including forward drilling, can be resumed. A person skilled in the art, who benefits from this disclosure, will recognize that the steps mentioned above can be performed in a different order based on one or more of the operator, driller, or rig procedures. A person skilled in the art will also recognize that a safe dynamic handover between MPD and well control maintains the wellbore fluids in a dynamic state. The methods disclosed herein enable the safe transition from MPD to well control and from well control to MPD of a CQzt? Ln / zznz / e / γΐΛΐ form that does not require the mud pumps to be stopped, thus ensuring a fluid dynamic state in the internal diameter of the well that advantageously avoids the formation of gels. Figure 3 shows an illustrative computer or control system 300 according to one or more embodiments of the present invention. A person skilled in the art will recognize that, as discussed above, a system for a safe dynamic handover between MPD and well control (e.g., 200 in Figure 2) may include a plurality of control systems (e.g., the MPD control system 190, the well control control system 290, and others not necessarily shown) that operate independently of each other from a device perspective but, optionally, may work together systematically to achieve the objectives of the safe dynamic handover method disclosed herein.Notwithstanding the foregoing, in certain embodiments, such control systems, or the functions or features implementing them, may be integrated or distributed based on the application or design in accordance with one or more embodiments of the present invention. A person skilled in the art will also recognize that the type or class of the MPD 190 control system and the well control system 290 may vary from one another, and from application to application, based on the application or design in accordance with one or more embodiments of the present invention. An illustrative computer or control system 300 may include one or more of a Central Processing Unit (CPU) 305, a host bridge 310, an Input / Output (I / O) bridge 315, a Graphics Processing Unit (GPU) 325, an Application-Specific Integrated Circuit (ASIC) (not shown), and a Programmable Logic Controller (PLC) (not shown) arranged on one or more printed circuit boards (not shown) that perform computational or logic operations. Each CPU 305, GPU 325, ASIC (not shown), and PLC (not shown) may be a single-core or multi-core device. Multi-core devices typically include a plurality of cores (not shown) arranged on the same physical die (not shown) or a plurality of cores (not shown) arranged on multiple dies (not shown) that are collectively arranged within the same mechanical package (not shown). The CPU 305 can be a general-purpose computing device that executes software instructions. The CPU 305 may include one or more of the following interfaces: 308 to the host bridge 310, 318 to system memory 320, and 323 to one or more I / O devices, such as, for example, one or more GPUs 325. The GPU 325 can serve as a specialized computing device that typically performs graphics functions related to frame buffer manipulation. However, a person skilled in the art will recognize that the GPU 325 can be used for CQzt? Ln / zznz / e / YiAi perform computationally demanding, non-graphics-related functions. In certain implementations, GPU 325 can interface 323 directly with CPU 305 (and indirectly interface 318 with system memory 320 via CPU 305). In other implementations, GPU 325 can interface 321 directly with host bridge 310 (and indirectly interface 316 or 318 with system memory 320 via host bridge 310 or CPU 305, depending on the application or design). In still other embodiments, the GPU 325 can directly interface 333 with the I / O bridge 315 (and indirectly interface 316 or 318 with the system memory 320 via the host bridge 310 or the CPU 305, depending on the application or design). A person skilled in the art will recognize that the GPU 325 also includes onboard memory.In certain embodiments, the functionality of the GPU 325 can be integrated, in whole or in part, with the CPU 305 and / or the host bridge 310. Host Bridge 310 can be an interface device that interconnects one or more computing devices and I / O Bridge 315 and, in some embodiments, System Memory 320. Host Bridge 310 can include interface 308 to CPU 305, interface 313 to I / O Bridge 315, for embodiments in which CPU 305 does not include interface 318 to System Memory 320, interface 316 to System Memory 320, and for embodiments in which CPU 305 does not include an integrated GPU 325 or interface 323 to GPU 325, interface 321 to GPU 325. The functionality of Host Bridge 310 can be fully or partially integrated with CPU 305 and / or GPU 325. The I / O bridge 315 can be an interface device that interconnects one or more computing devices and various I / O devices (e.g., 340, 345) and I / O expansion or add-on devices (not separately illustrated). The I / O bridge 315 can include interface 313 to the host bridge 310, one or more interfaces 333 to one or more I / O expansion devices 335, interface 338 to the keyboard 340, interface 343 to the mouse 345, interface 348 to one or more local storage devices 350, and interface 353 to one or more network interface devices 355. The functionality of the I / O bridge 315 can be fully or partially integrated with the CPU 305, the host bridge 310, and / or the GPU 325.Each local storage device 350, if any, can be a solid-state memory device, a group of solid-state memory devices, a hard disk drive, a group of hard disk drives, or any other non-transient, computer-readable media. The network interface device 355 can provide one or more network interfaces that include any network protocol suitable for facilitating network communications. CQzt? Ln / zznz / e / γΐΛΐ The control system 300 may include one or more network-attached storage devices 360 in addition to, or instead of, one or more local storage devices 350. Each network-attached storage device 360, if any, may be a solid-state memory device, a group of solid-state memory devices, a hard disk drive, a group of hard disk drives, or any other non-transient, computer-readable media. The network-attached storage device 360 ​​may or may not be co-located with the control system 300, and the control system 300 may access it through one or more network interfaces provided by one or more network interface devices 355. A person skilled in the art will recognize that the 300 control system can be either a conventional computer system or an application-specific computer system (not shown) configured for industrial applications. In certain embodiments, an application-specific computer system (not shown) can include one or more ASICs (not shown) or PLCs (not shown) that perform one or more specialized functions more efficiently. The one or more ASIOs (not shown) can interface directly with the CPU 305, the host bridge 310, or the GPU 325, or interface through the I / O bridge 315.Alternatively, in other embodiments, an application-specific computing system (not shown) may represent a reduced number of components required to perform a desired function or functions in an effort to reduce one or more of the chip count, printed circuit board footprint, thermal design power, and power consumption. In such embodiments, one or more ASICs (not shown) and / or PLCs (not shown) may be used in place of one or more of the CPU 305, host bridge 310, I / O bridge 315, or GPU 325, and may execute software instructions. In such systems, the one or more ASICs (not shown) or PLCs (not shown) may incorporate sufficient functionality to perform certain networking, computing, or logic functions in a minimal footprint and with a substantially smaller number of component devices. In this regard, a person skilled in the art will recognize that the CPU 305, host bridge 310, I / O bridge 315, GPU 325, an ASIC (not shown), or a PLC (not shown), or a subset, superset, or combination of functions or features thereof, may be integrated, distributed, or excluded, in whole or in part, based on the application, design, or form factor, in accordance with one or more embodiments of the present invention. Therefore, the description of the control system 300 is merely illustrative and is not intended to limit the type, class, or configuration of component devices that constitute a control system 300 suitable for performing computational operations in accordance with one or more embodiments of the present invention. CQzt? ιη / ζζηζ / Β / γίΛΐ invention. Notwithstanding the foregoing, a person skilled in the art will recognize that the 300 control system may be an industrial, stand-alone, portable, desktop, server, blade or rack-mountable system and may vary based on the application or design. In one or more embodiments of the present invention, a method for safe dynamic handover between pressure-managed drilling and well control may include identifying an unintentional influx of unknown formation fluids into a wellbore. One or more MPD choke manifold valves may be closed until the bottomhole pressure is sufficient to inhibit further influx of unknown formation fluids into the wellbore, sometimes referred to as killing the well. After experiencing the pressure hit, a determination may be made as to whether the volume of unknown formation fluids and the additional bottomhole pressure required to inhibit further influx exceeds an operating limit or matrix.If so, the pressure surge volume requires circulation out through the well control choke manifold, and a safe dynamic transfer from MPD to well control may include an initial transition that maintains a fluid dynamic state with respect to the wellbore fluids. In certain embodiments, an optional DFIT test can be performed to determine the maximum pump speed that can be used to circulate out the unknown formation fluid volume within the wellbore while maintaining the formation integrity. The drill string can then be spaced to ensure that there are no pipe splices in the path of a blind shear ram from the blowout preventer unit.A pressure setpoint for the MPD choke manifold can be set to a surface backpressure setpoint, and a pressure setpoint for the automated well control choke manifold can be set to a sensed pressure taken from below a blowout preventer (BOP) or a BOP choke line pressure. The drilling fluid injection rate can be reduced to maximize flow through the automated well control choke manifold.A pressure imbalance can be created by setting the MPD choke manifold pressure setpoint above the automated well control choke manifold pressure setpoint by a predetermined amount. This pressure imbalance will automatically cause the MPD control system to close the MPD choke manifold when the well control system opens the automated well control choke manifold. The sensed pressure or choke line pressure can be monitored to verify that it rises until the automated well control choke manifold closes. The CQzt? Ln / zznz / e / γΐΛΐ valve opens sufficiently so that the blowout preventer (BP) unit pressure or the choke line pressure remains constant. Then, after the MPD choke manifold has fully closed, an annular section of the BP unit can be closed. The BP unit's HCR valve can then be opened to allow flow through the BP unit choke line. Unknown formation fluids can be diverted from the BP unit choke line to the automated well control choke manifold for delivery to a mud and gas separator. Throughout this process, the wellbore remains in a fluid dynamic state due to the continuous, but not necessarily constant, injection of drilling fluids.In certain embodiments, a flow meter can be installed downstream of the automated well control choke manifold. A determination that unknown formation fluids have been circulated out of the wellbore can be made by a substantial equivalence in fluid density between the outflow and inflow. During the transition to, and throughout, well control operations, the wellbore remains in a fluid dynamic state. In certain embodiments, including marine applications, there may be gas-containing fluids in the marine riser. If gas is present within the now-isolated marine riser, the unknown formation fluids can be circulated out of the marine riser using the MPD choke manifold. Once unknown formation fluids are safely circulated out of the wellbore and potentially out of the marine riser in marine implementations, a safe dynamic handover from well control to MPD may include a second transition that also maintains a fluid dynamic state with respect to the wellbore fluids. In marine applications, the marine riser can be pressurized to equalize the pressure along the blowout preventer (BOP). Subsequently, in all applications, the BOP annulus can be opened. The pressure setpoint of the automated well control choke manifold can be set to the sensed pressure taken from below the BOP or the BOP choke line pressure.A second pressure imbalance can be created by setting the pressure setpoint of the automated well control choke manifold above the pressure setpoint of the MPD choke manifold by a second predetermined amount, where the second pressure imbalance automatically causes the well control control system to close the automated well control choke manifold when the MPD control system opens the manifold. CQzt? ιη / ζζηζ / Β / γίΛΐ MPD choke. The second predetermined amount may be less than, equal to, or greater than the predetermined amount used to create the pressure imbalance during the first transition from MPD to well control. Then, the HCR valve of the blowout preventer unit can be closed after the well control choke manifold has been closed. The wellbore's internal diameter remains in a fluid dynamic state due to the continuous, but not necessarily constant, injection of drilling fluids. At this point, the MPD system can be used to drill forward once more. In certain embodiments, the operation of both MPD and well control, including the transitions between them, can be automated.Although a human operator typically makes the decision regarding whether to circulate fluids to the outside through the MPD system or the well control system, all other steps can be performed by the MPD control system, the well control system, and potentially a computer running the hydraulic model. A person skilled in the art will recognize that a non-transient, computer-readable medium comprising software instructions that, when executed by a process, can perform one or more of the aforementioned methods in accordance with one or more embodiments of the present invention. The advantages of one or more embodiments of the present invention may include one or more of the following: In one or more embodiments of the present invention, a safe dynamic handover between MPD and well control provides, for the first time, the ability to automate MPD, well control operations and transitions between them while maintaining the internal wellbore diameter in a fluid dynamic state at all times, thereby increasing the reliability, efficiency and safety of operations. In one or more embodiments of the present invention, a safe dynamic handover between MPD and well control provides, for the first time, an automated well control choke manifold capable of regulating based on pressure rather than choke position to maintain the wellbore internal diameter in a fluid dynamic state during transitions between MPD and well control operations. In one or more embodiments of the present invention, a safe dynamic handover between MPD and well control governs the transitions from MPD to well control and from well control to MPD, wherein each transition is fluid dynamic with respect to the fluids within the internal well diameter, advantageously avoiding gel formation. In one or more embodiments of the present invention, a safe dynamic handover between MPD and well control ensures that unknown formation fluids within the wellbore's internal diameter are contained and circulated out of the internal diameter. CQzt? Ln / zznz / e / γΐΛΐ well in a safe and efficient manner, without ever reaching a static state with respect to the fluids of the internal diameter of the well. In one or more embodiments of the present invention, a safe dynamic transfer between MPD and well control prevents gel formation, thereby avoiding pressure spikes during mud pump startup. In one or more embodiments of the present invention, a safe dynamic handover between MPD and well control improves pressure transmission through the well system, thereby enabling precise pressure management during all phases of MPD, well control operations and transitions between them, while maintaining a fluid dynamic state within the internal wellbore diameter. In one or more embodiments of the present invention, a safe dynamic handover between MPD and well control increases the safety of operations by accurately managing pressure during all phases of MPD, well control, and transitions between them. In one or more embodiments of the present invention, a safe dynamic handover between MPD and well control maintains a fluid dynamic state with respect to the fluids within the internal wellbore diameter even if rotation has stopped, preventing gel-forming reactions that must be forcefully broken to resume MPD operations, such as forward drilling. Although the present invention has been described with respect to the embodiments mentioned above, those skilled in the art who benefit from this disclosure will recognize that other embodiments within the scope of the invention as disclosed herein may be devised. Accordingly, the scope of the invention should be limited only by the appended claims. It is hereby stated that, as of this date, the best method known to the applicant for putting the aforementioned invention into practice is the one that is clear from the present description of the invention.

Claims

1. A method for safe dynamic handover between managed pressure drilling and well control, characterized in that it comprises: establishing a pressure setpoint of an MPD choke manifold to a surface backpressure setpoint; establishing a pressure setpoint of an automated well control choke manifold to a sensed pressure taken from below a blowout preventer unit or a choke line pressure of the blowout preventer unit;create a pressure imbalance by setting the MPD choke manifold pressure setpoint above the automated well control choke manifold pressure setpoint by a predetermined amount, wherein the pressure imbalance automatically causes an MPD control system to close the MPD choke manifold when a well control system opens the automated well control choke manifold; verify that the sensed pressure or choke line pressure increases until the automated well control choke manifold opens sufficiently such that the blowout preventer unit pressure or choke line pressure remains constant; close the blowout preventer unit after the MPD choke manifold has been closed;and diverting unknown formation fluids from a choke line of the blowout prevention unit to the automated well control choke manifold for delivery to a mud and gas separator, where the internal wellbore diameter remains in a fluid dynamic state due to the continuous injection of drilling fluids.

2. The method according to claim 1, characterized in that it further comprises: identifying an unintentional inflow of unknown formation fluids into the internal diameter of the well.

3. The method according to claim 2, characterized in that it further comprises: closing one or more MPD choke manifold valves until the bottomhole pressure is sufficient to inhibit an additional influx of unknown formation fluids into the wellbore.

4. The method according to claim 3, characterized in that it further comprises: determining whether a volume of unknown formation fluids and sufficient bottomhole pressure to inhibit further inflow exceeds an operating limit that permits inflow circulation through the MPD choke manifold.

5. The method according to claim 4, characterized in that it further comprises: performing a Dynamic Formation Integrity Test to determine a maximum mud pump speed that can be used to circulate out the volume of unknown formation fluids within the internal diameter of the wellbore.

6. The method according to claim 5, characterized in that it further comprises: stopping the rotation and spacing a drill string to ensure that there is no pipe joint in the path of a blind shear ram or pipe ram of the blowout prevention unit.

7. The method according to claim 6, characterized in that it further comprises: stopping the booster while the MPD throttle manifold compensates for a loss of friction.

8. The method according to claim 7, characterized in that it further comprises: reducing a drilling fluid injection rate to maximize a flow rate through the automated well control choke manifold.

9. The method according to claim 8, characterized in that it further comprises: opening a Remote Hydraulic Control Valve of the blowout prevention unit that governs the flow through the throttle line of the blowout prevention unit.

10. The method according to claim 9, characterized in that it further comprises: completely closing the MPD throttling manifold.

11. The method according to claim 1, characterized in that it further comprises: CQzt? Ln / zznz / e / YiAi monitoring for potential gas within an insulated marine riser.

12. The method according to claim 11, characterized in that it further comprises: if there is gas inside the insulated marine riser, circulating fluids outside the marine riser using the MPD throttling manifold.

13. The method according to claim 1, characterized in that it further comprises: monitoring a flow of return fluids downstream of the well control choke manifold.

14. The method according to claim 1, characterized in that it further comprises: determining that the volume of unknown formation fluids has been circulated out of the internal diameter of the well by a substantial equivalence in fluid density between the outflow and inflow.

15. The method according to claim 1, characterized in that it further comprises: pressurizing a marine riser to equalize the pressure along the blowout preventer unit; opening the blowout preventer unit; setting the pressure setpoint of the automated well control choke manifold to the sensed pressure taken from below the blowout preventer unit or the choke line pressure of the blowout preventer unit;creating a second pressure imbalance by setting the pressure setpoint of the automated well control choke manifold above the pressure setpoint of the MPD choke manifold by a second predetermined amount, wherein the second pressure imbalance automatically causes the well control control system to close the automated well control choke manifold when the MPD control system opens the MPD choke manifold; and closing a Hydraulically Controlled Remote Valve of the blowout prevention unit after the well control choke manifold has been closed, wherein the wellbore internal diameter remains in a fluid dynamic state due to the continuous injection of drilling fluids.

16. The method according to claim 1, characterized in that it further comprises: opening the blowout prevention unit; setting the pressure setpoint of the automated well control choke manifold to the detected pressure taken from below the blowout prevention unit or the choke line pressure of the blowout prevention unit;creating a second pressure imbalance by setting the pressure setpoint of the automated well control choke manifold above the pressure setpoint of the MPD choke manifold by a second predetermined amount, wherein the second pressure imbalance automatically causes the well control control system to close the automated well control choke manifold when the MPD control system opens the MPD choke manifold, closing a Hydraulically Controlled Remote Valve of the blowout prevention unit after the well control manifold has been closed, wherein the internal wellbore diameter remains in a fluid dynamic state due to the continuous injection of drilling fluids.

17. A non-transient, computer-readable medium characterized in that it comprises software instructions that, when executed by a processor, perform a safe dynamic handover method between managed pressure drilling and well control comprising: setting a pressure setpoint of an MPD choke manifold to a surface backpressure setpoint; setting a pressure setpoint of an automated well control choke manifold to a sensed pressure taken from below a blowout preventer unit or a choke line pressure of the blowout preventer unit;create a pressure imbalance by setting the MPD choke manifold pressure setpoint above the automated well control choke manifold pressure setpoint by a predetermined amount, wherein the pressure imbalance automatically causes an MPD control system to close the MPD choke manifold when a well control system opens the automated well control choke manifold; verify that the sensed pressure or choke line pressure increases until the automated well control choke manifold opens sufficiently such that the blowout preventer unit pressure or choke line pressure remains constant; close the blowout preventer unit after the MPD choke manifold has been closed;and diverting unknown formation fluids from a choke line of the blowout prevention unit to the automated well control choke manifold for delivery to a mud and gas separator, where the internal wellbore diameter remains in a fluid dynamic state due to the continuous injection of drilling fluids.

18. The non-transient computer-readable medium according to claim 17, characterized in that the method further comprises: identifying an unintentional influx of unknown formation fluids into the internal diameter of the well.

19. The non-transient computer-readable medium according to claim 18, characterized in that the method further comprises: closing one or more pressure-managed drill choke manifold valves until the bottomhole pressure is sufficient to inhibit an additional influx of unknown formation fluids into the wellbore.

20. The non-transient computer-readable medium according to claim 19, characterized in that the method further comprises: determining whether a volume of unknown formation fluids and sufficient bottomhole pressure to inhibit further inflow exceeds an operating limit that permits inflow circulation through the MPD choke manifold.

21. The non-transient computer-readable medium according to claim 20, characterized in that the method further comprises: performing a Dynamic Formation Integrity Test to determine a maximum mud pump speed that can be used to circulate out the volume of unknown formation fluids within the internal diameter of the wellbore.

22. The non-transient computer-readable medium according to claim 21, characterized in that the method further comprises: stopping the rotation and spacing a drill string to ensure that there is no pipe joint in the path of a blind shear ram or pipe ram of the blowout prevention unit.

23. The non-transient computer-readable medium according to claim 22, characterized in that the method further comprises: stopping the booster while the MPD choke manifold compensates for a loss of friction.

24. The non-transient computer-readable medium according to claim 23, characterized in that the method further comprises: CQzt? Ln / zznz / e / γΐΛΐ reducing a drilling fluid injection rate to maximize a flow rate through the automated well control choke manifold.

25. The non-transient computer-readable medium according to claim 24, characterized in that the method further comprises: opening a Remote Hydraulic Control Valve of the blowout prevention unit that governs the flow through the throttle line of the blowout prevention unit.

26. The non-transient computer-readable medium according to claim 25, characterized in that the method further comprises: completely closing the MPD choke manifold.

27. The non-transient computer-readable medium according to claim 17, characterized in that the method further comprises: monitoring for potential gas within an insulated marine riser.

28. The non-transient computer-readable medium according to claim 27, characterized in that the method further comprises: if there is gas inside the insulated marine riser, circulating the fluids out of the marine riser using the MPD throttling manifold.

29. The non-transient computer-readable medium according to claim 17, characterized in that the method further comprises: monitoring a flow of return fluids downstream of the well control choke manifold.

30. The non-transient computer-readable medium according to claim 17, characterized in that the method further comprises: determining that the volume of unknown formation fluids has been circulated out of the internal diameter of the well by a substantial equivalence in fluid density between the outflow and inflow.

31. The non-transient, computer-readable medium according to claim 17, characterized in that the method further comprises: pressurizing a marine riser to equalize the pressure along the blowout preventer unit; opening the blowout preventer unit; setting the pressure setpoint of the automated well control choke manifold to the sensed pressure taken from below the blowout preventer unit or the choke line pressure of the blowout preventer unit;creating a second pressure imbalance by setting the pressure setpoint of the automated well control choke manifold above the MPD choke manifold pressure setpoint by a second predetermined amount, wherein the second pressure imbalance automatically causes the well control control system to close the automated well control choke manifold when the MPD control system opens the MPD choke manifold; and closing a Hydraulically Controlled Remote Valve of the blowout prevention unit after the well control choke manifold has been closed, wherein the wellbore internal diameter remains in a fluid dynamic state due to the continuous injection of drilling fluids.

32. The non-transient, computer-readable medium according to claim 17, characterized in that the method further comprises: opening the blowout preventer unit; setting the pressure setpoint of the automated well control choke manifold to the sensed pressure taken from below the blowout preventer unit or the choke line pressure of the blowout preventer unit; creating a second pressure imbalance by setting the pressure setpoint of the automated well control choke manifold above the pressure setpoint of the MPD choke manifold by a second predetermined amount, wherein the second pressure imbalance automatically causes the well control control system to close the automated well control choke manifold when the MPD control system opens the MPD choke manifold;and close a Hydraulically Controlled Remote Valve of the blowout prevention unit after the well control choke manifold has been closed, where the internal wellbore diameter remains in a fluid dynamic state due to the continuous injection of drilling fluids.;

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