EA042987B1 - HIERARCHICAL PRESSURE CONTROL FOR DRILLING UNDER PRESSURE CONTROL - Google Patents

Description

Cross-references to related applications

An application for this invention claims the benefits, or priority, of U.S. Patent Application Ser. July 2019, both of which are hereby incorporated by reference in their entirety.

Prerequisites for the creation of the invention

A closed-loop hydraulic drilling system can be used to perform a variety of Managed Pressure Drilling (MPD) solutions that focus on controlling wellbore pressure during drilling and other operations by controlled application of back pressure at the wellhead. Typically, an annulus sealing system is used to controlly seal the annulus surrounding the drill string, and controlled back pressure is applied to the wellhead by adjusting the choke orifice setting, sometimes referred to as choke position, of one or more choke valves of a surface-mounted MPD choke manifold that are connected on the fluid medium with one or more diversion systems diverting to the surface return fluids from or from under the annulus seal. Each choke valve is typically configured to be in a fully open state where flow is unobstructed, a fully closed state where flow is stopped, and multiple states in between where flow is restricted.

In order to maintain well control, during conventional drilling operations, one or more MPD solutions can be used to control the pressure in the wellbore within a safe pressure gradient limited by the pore pressure or collapse pressure, if the collapse pressure is higher than the pore pressure, and the fracture pressure. . By maintaining control over the well, unwanted influx of formation fluids into the wellbore is prevented and the integrity of the formation is maintained, thereby preventing its hydraulic fracturing. If the annulus pressure falls below the lower threshold, one or more of the MPD choke manifold valves may be closed to the extent necessary to increase the annulus pressure to the desired value. Similarly, if the annulus pressure increases above an upper threshold, one or more of the MPD choke manifold valves may be opened to the extent necessary to lower the annulus pressure to the desired value. MPD engineering solutions are adopted for use in a variety of drilling and other applications, as well as emergency response engineering solutions.

Brief summary of the invention

According to one aspect of one or more embodiments of the present invention, a hierarchical pressure control method for controlled pressure drilling operations includes receiving a measured pressure value. If the measured pressure exceeds the MPD pressure setpoint, one or more choke valves of the MPD choke manifold are commanded to open until the measured pressure is approximately equal to the MPD pressure setpoint or a command is received to move to a fully open choke setting. If at any time the measured pressure exceeds the pressure control valve setpoint, the MPD in-line manifold is put into standby mode and one or more valves of the pressure control valve system are commanded to open until the measured pressure falls below the control valve setpoint. pressure or no command is received to go to the plant with the pressure control valve fully open. If at any time the measured pressure exceeds the pressure relief valve set point, the pressure relief valve is commanded to open.

In accordance with one aspect of one or more embodiments of the present invention, the non-volatile computer-readable medium comprises software instructions that, when executed by a processor, execute a hierarchical pressure control method for controlled pressure drilling operations, including receiving a measured pressure value. If the sensed pressure exceeds the MPD pressure setpoint, one or more choke valves of the MPD choke manifold are commanded to open until the sensed pressure is approximately equal to the MPD pressure setpoint or a command is received to move to a fully open choke setting. If at any time the measured pressure exceeds the pressure control valve setpoint, the MPD in-line manifold is placed on standby and one or more valves in the pressure control valve system are commanded to open until the measured pressure falls below the control valve setpoint. pressure or no command is received to go to the plant with the pressure control valve fully open. If at any time the sensed pressure exceeds the pressure relief valve set point, the pressure relief valve is commanded to open.

- 1 042987

According to one aspect of one or more embodiments of the present invention, a hierarchical pressure control system for controlled pressure drilling comprises an annulus sealing system that provides an annular seal surrounding a drill string, a pressure sensor that measures pressure, and an MPD choke manifold comprising a plurality of choke valves, wherein at least one choke valve is in fluid communication with a flowline that removes return drilling fluid from or under the annular seal to apply back pressure to the wellhead. The system further comprises an MPD control system that commands one or more choke valves of the MPD choke manifold to command an MPD pressure setpoint, a plurality of valves of the pressure control valve system, where at least one pressure control valve is in fluid communication with the flow line, discharging return drilling fluid into a mud gas separator, vibrating screen, or other drilling fluid separation and purification system, and a pressure control valve control system that commands one or more valves of the pressure control valve system to open when the sensed pressure exceeds a valve set point pressure regulation. The system further comprises a pressure relief valve that vents the return drilling fluid into the mud gas separator, shaker or overboard, and a pressure relief valve control system that commands the pressure relief valve to open when the sensed pressure exceeds a set value for the pressure relief valve. .

Other aspects of the present invention will be apparent from the following description and claims.

Brief description of graphic materials

In FIG. 1 shows a conventional closed-loop hydraulic drilling system for controlled pressure drilling operations.

In FIG. 2A shows an illustrative graph of MPD choke position, wellhead backpressure, pressure relief valve set point, and pressure relief valve position when the MPD choke manifold becomes clogged, fails, or other unforeseen circumstances occur, wellhead backpressure increases and the pressure relief valve is actuated. act as a safety device in a traditional closed-loop hydraulic drilling system.

In FIG. 2B shows an illustrative plot of pore pressure, fracture pressure, and wellbore pressure when an MPD choke manifold plugs, fails, or other unforeseen circumstances occur, wellbore pressure rises and a pressure relief valve is actuated as a safety device in a conventional closed-loop hydraulic drilling system. system.

In FIG. 3 shows a hierarchical pressure control system for controlled pressure drilling in accordance with one or more embodiments of the present invention.

In FIG. 4 shows a hierarchical pressure control method for controlled pressure drilling in accordance with one or more embodiments of the present invention.

In FIG. 5A shows an illustrative plot of MPD choke position, wellhead back pressure, pressure control valve setpoint, pressure control valve setting, pressure relief valve setpoint, and pressure relief valve position when a pressure control valve system is used to supplement an MPD choke manifold in control. wellbore pressure within a safe pressure gradient in a hierarchical pressure control system for controlled pressure drilling operations in accordance with one or more embodiments of the present invention.

In FIG. 5B shows an illustrative plot of pore pressure, fracture pressure, and wellbore pressure when a pressure control valve system is used to supplement an MPD choke manifold while controlling wellbore pressure within a safe pressure gradient in a hierarchical pressure control system for controlled pressure drilling according to with one or more embodiments of the present invention.

In FIG. 6 shows an exemplary computer or control system in accordance with 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, the same elements in the various figures are designated by the same reference numerals. In the following detailed description of the present invention, specific details are set forth in order to provide a thorough understanding of the present invention. In other cases, features that are well known to a person skilled in the art are not described in order to avoid obscuring the description of the present invention.

- 2 042987

In challenging environments, including deep and ultra-deep operations, the ability to manage wellbore pressure and respond to unforeseen circumstances is critical to operational safety as well as environmental protection. As such, it is standard industry practice to maintain control of the well during drilling and other activities. From a pragmatic point of view, well control refers to the ability of a drilling rig to cope with the potentially damaging results of an unwanted influx of unknown formation fluids, sometimes referred to as water hammer, into the well system. Unknown reservoir fluids may contain explosive gases that pose a significant safety hazard and have the potential to lead to a sudden release. Additionally, well control prevents hydraulic fracturing, thereby protecting the structural integrity of the wellbore. One way in which well control is maintained during conventional MPD operations is to maintain wellbore pressure within a safe pressure gradient limited by pore pressure, or collapse pressure if higher than pore pressure, and fracturing pressure. However, as operators and drillers follow an increasingly complex drilling plan, being able to maintain control of the well requires careful orientation within narrow margins of safe pressure gradients with very little margin for error that change with depth.

In such a complex operation, unforeseen circumstances inevitably arise, and the rig must be able to respond quickly and proportionately to regain control of the well. Conventional responses to such contingencies include, for example, disabling a blowout preventer (BOP), injecting mud to kill a flowing well, and pumping unknown formation fluids. As such, traditional methods of responding to unforeseen circumstances lead to a shutdown of drilling operations, pose a significant threat to the safety of personnel on the drilling rig, and lead to environmental pollution. A significant disadvantage of standard industry practice is that it is reactive in nature, with drastic measures taken only after contingencies have already arisen, compromising the safety of rig personnel and potentially resulting in environmental pollution. Therefore, there is a long felt but unresolved need in the industry to increase the ability to prevent such contingencies in the first place.

Accordingly, in one or more embodiments of the present invention, a method and system for hierarchical pressure control for MPD operations uses an intelligent and programmable pressure control valve (PCV) system comprising a PCV control system and one or more PCV system valves to enhance the drilling rig's ability to maintain wellbore pressure within a safe pressure gradient and reduce or eliminate situations in which a pressure relief valve (PRV) is used to respond to contingencies and which, despite the use of a PRV, often results in wellbore pressure exceeding the fracturing pressure or it falls below the pore pressure. In conventional MPD operations, an MPD choke manifold may be used to apply wellhead back pressure and control wellbore pressure. An independent PCV control system can be programmed to open one or more valves of the PCV system when the wellbore pressure exceeds a setpoint for the PCV. The PCV setpoint may be set to a pressure value that is less than the PRV setpoint, or actuation value, by a difference sufficient to allow the PCV system to fully open the PCV system valves before activating the PRV. When the wellbore pressure exceeds the PCV setpoint, one or more valves in the PCV system may open and direct flow to a mud gas separator (MGS), vibrating screen, or other mud separation and purification system to prevent further pressure buildup in the wellbore. and at the same time prevent the pressure drop in the wellbore that normally occurs when a PRV is opened. The PCV system may include heavy clipping and control, allowing it to respond quickly and efficiently.

When the PCV system is activated, the MPD in-line manifold can be put into standby mode and retain its last position. If the pressure stabilizes at or near the PCV setpoint, the drilling crew can then investigate the root cause of the high pressure and attempt to correct the problem while the wellbore pressure is maintained at a safe level. Once the pressure problem has been resolved, flow to the MPD inlet manifold may be resumed and the pressure will continue to fall to or near the MPD pressure setpoint. As the pressure decreases, the PCV system will continue to close one or more valves until it reaches a fully closed state in which the pressure drops below the PCV setpoint, at which point normal operation can be resumed with flow through the choke only. MPD collector. If an MPD choke manifold supplemented with a PCV system is unable to maintain wellbore pressure, as a precaution to

- 3 042987 PRV can be used as a last resort. Advantageously, the hierarchical pressure control method and system for MPD operations protect the integrity of the wellbore without the need to close the BOP or other drastic measures, while the traditional use of PRV exclusively is focused only on protecting equipment from pressure-related damage and does not protect the wellbore from hydraulic fracturing, and when the PRV is activated, it usually requires the VOR to be turned off or other drastic measures to be taken.

In FIG. 1 shows a conventional closed-loop hydraulic drilling system 100 for MPD operations. A conventional closed-loop hydraulic drilling system 100 made for offshore drilling operations is shown for purposes of illustration only. While offshore applications require additional components, such as a riser, to facilitate drilling of a subsea wellbore, one skilled in the art will appreciate that onshore applications are substantially similar in configuration and function to the components required for MPD operations. Conventional closed-loop hydraulic drilling system 100 typically includes a conventional MPD system (e.g., annulus sealing system 110, annulus closure system 115, and flow diverter 120), a bottom of a riser system 125, and a BOP 130. Those skilled in the art will appreciate that the drilling system 100 may include other components, such as, for example, an emergency retractor (not shown), a ball joint (not shown), and an expandable sleeve (not shown), which are typically located above a conventional MPD system and are not shown.

A conventional MPD system typically comprises an annular seal system 110, an annulus closure system 115 located below the annulus seal system 110, and a diverter 120 located below the annulus closure system 115. The annulus seal system 110 under control seals the annulus 108 surrounding the drill string 135 so that it is enclosed in a shell. The annular seal system 110 may be a rotary control device (RCD), an active control device (ACD), or any other type or form of system configured to create an annular seal such that wellbore pressure can be controlled by applying back pressure at the wellhead. The annulus closure system 115 may be a back-up system to maintain the annular seal during connections or when the annulus seal system 110 or its components is installed, maintained, or replaced. The flow diverter 120 diverts return mud from or under the annular seal to an MPD choke manifold 145, which directs this return mud to mud separation and purification systems (e.g., MGS 155 or vibrating screens 160) for recycling and reuse. The diversion device 120 is positioned above and in fluid communication with the bottom of the riser system 125. The bottom of the riser system 125 is positioned above and in fluid communication with a BOP 130 located on or near the seafloor 104. A BOP 130 is positioned above and in fluid communication with a wellhead (not shown separately) which is positioned above and in fluid communication with the wellbore 106 being drilled. The central lumen extends through a conventional MPD system (e.g., annulus seal system 110, annulus closure system 115, and diverter 120), the bottom of the riser system 125, the BOP 130, the wellhead (not shown separately), and into the wellbore 106 to facilitate drilling and other works. The drill string 135 may be passed through the central lumen and includes at the distal end a drill bit 140 used to drill the wellbore 106 .

During MPD operations, one or more mud pumps 170 are under control to pump mud (not shown) from the mud reservoir 165 into the wellbore through the bore of the drill string 135. Return mud (not shown) is returned through the annulus 108 surrounding the drilling column 135, and is controlled by diverter 120 through flowline 122 to one or more choke valves (not shown separately) of MPD choke manifold 145. One or more MPD choke manifold 145 choke valves are controlled to direct flow through flowline 147 to flowmeter 150, and flowmeter 150 directs flow through flowline 153 to one or more mud separation and purification systems, including, for example, MGS 155 and /or vibrating screens 160 to separate and clean before returning the treated mud (not shown) to the mud tanks 165 for reuse. One or more pressure sensors (not shown) are placed at various locations along the flow path to measure the pressure of the return drilling fluid (not shown).

The MPD control system 600a may receive pressure sensor data (not shown) and flowmeter 150 data in approximately or near real time. One of ordinary skill in the art will understand what approximately or near real time means practically at the moment of measurement, with a delay only due to measurement, calculation and/or transmission, but usually on the order of fractions of a second or no more than a few seconds. The MPD control system 600a may command

- 4 042987 one or more choke valves (not shown separately) of the choke manifold 145 MPD to go to the desired choke setting and/or flow command on the mud pumps 170, thereby controlling the pressure in the wellbore. The tight annulus seal provided by the annulus sealing system 110 allows precise control of wellbore pressure by adjusting the orifice of one or more choke valves (not shown separately) of the choke manifold 145 MPD and applying back pressure to the wellhead accordingly. The choke opening, sometimes referred to as the choke position, of one or more choke valves (not shown separately) of a 145 MPD choke manifold corresponds to the amount, usually expressed as a percentage, by which the choke valves (not shown separately) or the 145 MPD choke manifold itself are opened and allowed to flow flow.

For example, one or more choke valves (not shown separately) of the 145 MPD choke manifold may be fully open with flow unobstructed, fully closed with flow stopped, or partially open or closed with flow restricted according to the degree in which they are open or closed. If the choke operator needs to pressurize the wellbore, the choke orifice setting of one or more choke valves (not shown separately) of the 145 MPD choke manifold can be reduced to further restrict mud flow and apply additional back pressure to the wellhead. Similarly, if the choke operator needs to reduce wellbore pressure, the choke orifice setting of one or more choke valves (not shown separately) of the 145 MPD choke manifold can be increased to increase mud flow and decrease the amount of applied back pressure at the wellhead. As such, back pressure MPD systems typically control wellbore pressure by adjusting the choke orifice setting of one or more choke valves (not shown separately) of the MPD choke manifold 145 and/or the flow rate on the mud pumps 170 introducing drilling fluid into the wellbore, based on at least pressure sensor data.

The PRV control system 600c controls the PRV 175 and serves as a separate and independent safeguard to protect the rig equipment from damage due to high and typically uncontrollably rising pressures in the system 100. The PRV control system 600c may receive or generate pressure transducer data or other data. approximately or almost in real time. The PRV control system 600c typically stores a PRV setpoint that sets the pressure at which the PRV 175 fires and opens. Typically, the setpoint for PRV is chosen as the pressure value that protects the weakest link in the drilling system 100 from pressure damage, often the riser system 125 in offshore applications. Once opened, the PRV 175 may discharge return drilling fluid from the annulus 108 into a mud separation and purification system (eg, MGS 155 or shakers 160) or overboard 180 in offshore applications. While the PRV 175 protects the rig equipment and is designed to release as much pressure as possible as quickly as possible, it does not maintain pressure in the wellbore, potentially compromising the structural integrity of the wellbore and the rig's ability to carry out subsequent MPD operations. Thus, the use of PRV 175 as a last resort results in a cessation of drilling operations and usually requires drastic measures, including, for example, shutting down the BOP 130, to keep the well safe, thereby greatly increasing costs and jeopardizing the possibility restoration of well control and resumption of drilling operations.

In FIG. 2A is an illustrative plot of MPD choke position, wellhead backpressure, PRV set point, and PRV position when an MPD choke manifold (e.g., 145 in FIG. 1) becomes clogged, fails, or other unforeseen circumstances occur, wellhead backpressure rises. and PRV (eg, 175 in FIG. 1) is actuated as an emergency safety device in a traditional closed-loop hydraulic drilling system (eg, 100 in FIG. 1). Initially, the position of the MPD choke and the corresponding wellhead back pressure are relatively constant, which is to be expected during normal drilling operations. In the event that one or more choke valves in an MPD choke manifold (e.g., 145 in Figure 1) begin to clog, fail, or other unforeseen circumstances occur, wellhead backpressure may begin to rise for reasons other than the intentional closure of one or several in-line valves of an MPD in-line manifold (for example, 145 in Fig. 1). The MPD control system (eg, 600a in FIG. 1) may, in response to rising wellhead back pressure, command one or more choke valves of the MPD choke manifold (eg, 145 in FIG. 1) to open in an attempt to stabilize the pressure. However, even after one or more choke valves of an MPD choke manifold (eg, 145 in FIG. 1) are commanded to go into a fully open choke set, wellhead backpressure continues to rise, as shown in the depicted example. After the wellhead backpressure exceeds the PRV setpoint, the PRV control system (for example, 600s in Fig. 1)

- 5 042987 is triggered and commands the PRV (for example, 175 in Fig. 1) to come into action as a last resort to quickly release all pressure in the system (for example, 100 in Fig. 1), including in the wellbore, without taking into account the strong impact on the structural integrity of the wellbore.

In continuation, in FIG. 2B shows an illustrative plot of pore pressure, fracture pressure, and wellbore pressure when an MPD choke manifold (eg, 145 in FIG. 1) plugs, fails, or other contingency occurs, as described in the previous example in FIG. 2A, wellbore pressure builds up and the PRV (eg, 175 in FIG. 1) is activated as a last resort in a traditional closed-loop hydraulic drilling system (eg, 100 in FIG. 1). In FIG. 2B uses a common timeline from FIG. 2A. In the illustrated example, a safe pressure gradient can be established by pore pressure and fracture pressure as shown. Initially, the wellbore pressure closely follows the pore pressure, but is slightly higher, but the well is within a safe pressure gradient. When one or more choke valves in an MPD choke manifold (eg, 145 in FIG. 1) begin to clog, fail, or other unforeseen circumstances occur, the pressure in the wellbore begins to increase. As shown in FIG. 2A, the MPD control system (eg, 600a in FIG. 1) attempts to maintain wellbore pressure within a safe pressure gradient by opening one or more MPD choke manifold choke valves (eg, 145 in FIG. 1). However, the MPD choke manifold (eg, 145 in FIG. 1) is unable to maintain wellbore pressure within a safe pressure gradient, and when the wellhead backpressure exceeds the set value for PRV, the PRV (eg, 175 in FIG. 1) is driven act as a last resort to protect rig equipment from high pressure damage. While the PRV (eg, 175 in FIG. 1) is successful in depressurizing the system quickly, it is not capable of controlling the wellbore. Returning to FIG. 2B, as shown in this example, the wellbore pressure exceeds the fracture pressure for a period of time before the PRV (e.g., 175 in FIG. 1) can depressurize, and similarly on the other side of the safe pressure gradient, the wellbore pressure drops below the pore pressure for a period of time, and all this is not unexpected since the PRV (eg 175 in Fig. 1) simply depressurizes the system (eg 100 in Fig. 1) to prevent high pressure damage. As a consequence, hydraulic fracturing may occur in the wellbore, which will likely require the closure of the BOP (e.g., 130 in Fig. 1) and other necessary drastic measures before drilling operations can be resumed, if they can be resumed at all. .

In FIG. 3 shows an improved hierarchical pressure control hydraulic drilling system 300 for MPD operations, in accordance with one or more embodiments of the present invention. An embodiment of a drilling system 300 for offshore drilling operations is shown and described herein for purposes of illustration only. While offshore applications differ from onshore applications in that they require additional equipment to facilitate drilling of a subsea wellbore, one skilled in the art will appreciate that onshore applications are a subset substantially similar in terms of the configuration and function of the components required for MPD works. As such, one or more embodiments of the present invention are contemplated and used in both onshore and offshore applications. One skilled in the art will appreciate that the components and component configuration of the drilling system 300 may vary depending on the application or design in accordance with one or more embodiments of the present invention and is not limited to the exemplary system 300 described herein.

In one or more embodiments of the present invention, one or more components of a conventional MPD system may be used to perform MPD operations. The annulus sealing system 110, or a functional equivalent thereof, may be used to controllably seal the annulus 108 surrounding the drill string 135 such that it is enclosed and not exposed to the atmosphere. The annular seal system 110 may be an RCD, ACD, or any other type or form of system configured to form an annulus seal such that wellbore pressure can be controlled by applying back pressure at the wellhead. In some embodiments, the annulus closure system 115, or a functional equivalent thereof, may be placed below the annulus sealing system 110 as a back-up system to maintain the annulus seal during a connection, or when the annulus sealing system 110 or its components is installed, maintained, or replaced. However, the annular closure system 115 may not be included in systems 300 for onshore or low specification applications. The diversion device 120, or a functional equivalent thereof, may be located below the annular closure system 115, or at least below the annular seal in embodiments that do not include an annulus closure.

- 6 042987 system 115, and diverts the return drilling mud from or under the annular seal to the 145 MPD Choke Manifold, which, under control, diverts the return drilling mud into mud separation and purification systems (e.g. MGS 155 or 160 vibrators) for processing and reuse. One skilled in the art will appreciate that the annular seal system 110, annular closure system 115, and diverter 120, or the functions and features they implement, may be included, omitted, incorporated, or distributed among one or more components or riser sections. depending on the application or design in accordance with one or more embodiments of the present invention. For example, for illustrative purposes only, in some onshore or low specification applications, diversion device 120 may be incorporated into RCD 110 in a drilling system 300 that does not include annular closure system 115.

In offshore applications, the diversion device 120 may be placed above and in fluid communication with the bottom of the riser system 125, and the bottom of the riser system 125 may be placed above and in fluid communication with the BOP 130 located at or near the bottom of the riser system 125. seafloor 104. In onshore applications, the diversion device 120 may be placed above and in fluid communication with the BOP 130. The BOP 130 may be placed above and in fluid communication with the wellhead (not shown separately), which may be placed above and in fluid communication with the wellhead (not shown separately). in fluid communication with the wellbore 106 being drilled. The central lumen may extend through a conventional MPD system (e.g., annulus seal system 110, annulus closure system 115, and/or diverter 120), the bottom of the riser system 125, the BOP 130, the wellhead (not shown separately), and into the wellbore 106 wells to facilitate drilling and other work. The drill string 135 may be passed through the central lumen and includes at its distal end a drill bit 140 used to drill the wellbore 106 .

In one or more embodiments of the present invention, the advanced drilling system 300 may be configured to implement a hierarchical pressure control method for MPD operations. In such embodiments, while the MPD inlet manifold 145 remains the primary pressure control device under normal operating conditions, an intelligent and programmable PCV system comprising a PCV control system 600b and one or more PCV system valves 320 can be used to supplement the MPD inlet manifold 145's ability to maintain wellbore pressure within a safe pressure gradient in the event that one or more choke valves of the 145 MPD choke manifold become clogged, fail, or other unforeseen circumstances occur such that the 145 MPD choke manifold cannot maintain wellbore pressure on its own. As long as the PCV control system helps maintain wellbore pressure, rig personnel can investigate the root cause of pressure problems while the structural integrity of the wellbore is protected from adverse pressure changes. In the event that MPD choke manifold 145 and one or more PCV system valves 320 are unable to adequately control wellbore pressure, PRV 175 can act as a last resort to protect rig equipment from high pressure by releasing all system pressure.

During MPD operations, one or more mud pumps 170 may be controlled to pump mud (not shown) from the mud reservoir 165 into the wellbore through the bore of the drill string 135. Return mud (not shown) returns through the annulus 108 surrounding the drill string 135, and can be controlled by diverter 120 or functional equivalent through flowline 122 to MPD choke manifold 145. Choke manifold 145 MPD can be controlled to direct flow through flow line 147 to flow meter 150, and flow meter 150 can direct flow through flow line 153 to one or more mud separation and purification systems, including, for example, MGS 155 and/or vibrating sieves 160 to separate and clean before returning the treated mud (not shown) to the mud tanks 165 for reuse. One or more pressure sensors (not shown) may be placed at various locations along the flow path to measure the pressure in the system 300. For example, individual pressure sensors (not shown) may be used to provide pressure measurements at various locations throughout the system, as well as pressure transducers incorporated (not shown separately) in one or more of the 145 MPD in-line manifold, one or more of the 320 PCV or PRV 175 valves.

As a first level of hierarchical pressure control, MPD control system 600a may receive measured pressure values from one or more pressure sensors (not shown) and/or measured flow rates from flowmeter 150 in approximately or near real time. One skilled in the art will appreciate that MPD choke manifold 145 may include a plurality of choke valves (not shown separately) that can be individually or collectively controlled by MPD control system 600a. The MPD control system 600a can supply one

- 7 042987 or several choke valves of the MPD choke manifold 145 command to move to the desired setting, or position, of the choke opening and/or command the flow rate of the mud pumps 170, thereby controlling the pressure in the wellbore. The tight annulus seal provided by the annulus sealing system 110 allows wellbore pressure to be controlled by adjusting the choke orifice of one or more choke valves of the MPD choke manifold 145 and applying back pressure to the wellhead accordingly. While each choke valve may have an independently controlled choke orifice setting, or position, one skilled in the art will appreciate that reference to choke orifice setting or position may refer to the independent capability of one or more choke valves of a 145 MPD choke manifold, or 145 MPD inline manifold, direct flow depending on application or design. The orifice, or position, of the choke of one or more choke valves or the collective choke manifold 145 MPD may correspond to the amount, usually expressed as a percentage, by which one or more choke valves, or the collective choke manifold 145 MPD, opens and is able to flow.

For example, one or more of the choke valves of the choke manifold 145 MPD may be fully open with flow unobstructed, fully closed with flow stopped, or partially open/closed with flow restricted. If the choke operator needs to pressurize the wellbore, the choke orifice setting of one or more choke valves or the 145 MPD choke manifold can be reduced to further restrict mud flow and apply additional back pressure to the wellhead. Similarly, if the choke operator needs to reduce the pressure in the wellbore, the choke orifice setting of one or more choke valves or the total choke manifold 145 MPD can be increased to increase mud flow and reduce the amount of applied back pressure at the wellhead. As such, wellbore pressure control may be accomplished by adjusting the choke orifice setting of one or more choke valves or the total choke manifold 145 MPD and/or the flow rate of the mud pumps 170 introducing drilling fluid into the wellbore based on at least pressure sensor data, corresponding to the measured pressure values.

As a second level of hierarchical pressure control, an independent intelligent and programmable PCV control system 600b can control one or more PCV system valves 320 to supplement and assist the MPD choke manifold 145 in maintaining wellbore pressure under certain conditions. The PCV control system 600b or one or more PCV system valves 320 may include a built-in pressure sensor or meter (not shown) and/or receive measured pressure values from one or more separate (not shown) or built-in (not shown) pressure sensors in other equipment. To reduce the number of times the PRV 175 opens, the PCV system can command to open one or more of the PCV system valves 320 to provide an additional flow path for return drilling fluid in an attempt to reduce the buildup of pressure in the system, which ideally prevents the system from 300 the need to actuate the PRV 175. The PCV setpoint for one or more PCV valves 320 can be defined as a pressure below the PRV setpoint that causes one or more PCV valves 320 to open before the PRV 175 is actuated and below the fracture pressure. When one or more valves 320 of the PCV system are opened, the PCV system seeks to maintain the setpoint as constant as possible.

The PCV system may include heavy clipping and control, allowing it to respond quickly and efficiently. Unlike the PRV 175, whose primary purpose is to protect the rig equipment from large pressure changes, the PCV system also protects the integrity of the wellbore by not allowing the wellbore pressure to exceed the fracture pressure or fall below the pore pressure (or collapse pressure if the collapse pressure is higher than pore pressure). Thus, if the 145 MPD choke manifold becomes plugged, fails, or otherwise loses its ability to control wellbore pressure for any reason, the PCV system can open an additional flow path to help control wellbore pressure without the need to actuate the PRV 175 , turn off the VOR 130 or take other drastic measures.

As a third level of hierarchical pressure control, the PRV control system 600c may control the PRV 175 and serve as a separate and independent safety device to protect rig equipment from damage due to high and typically uncontrollably rising pressures in the system 300. The PRV control system 600c may receive measured values. pressure from one or more pressure sensors (not shown), measured flow rates from the flow meter 150 in near or near real time, or other data in near or near real time. The PRV control system 600c may store a PRV setpoint that sets the pressure at which the PRV 175 fires and opens. Usually given

- 8 042987 the value for PRV is chosen as the pressure value protecting the weakest link in the drilling system 100, in offshore applications often the riser system 125. Once opened, the PRV 175 can discharge return drilling fluid from the annulus 108 into a mud separation and purification system (such as MGS 155 or 160 vibrators) or overboard 180. Although the PRV 175 protects the rig equipment and is designed to discharge as much pressure as possible as quickly as possible, it does not maintain or control pressure in the wellbore, potentially compromising the structural integrity of the wellbore and the rig's ability to carry out subsequent MPD operations. Thus, the use of PRV 175 as a last resort results in a cessation of drilling operations and usually requires drastic measures, such as shutting down the BOP 130, to keep the well safe, which greatly increases the costs required to restore well control and resume drilling operations. if at all possible to do so.

With multi-level hierarchical pressure control, if the 145 MPD choke manifold cannot control the wellbore pressure during drilling operations and the wellbore pressure continues to increase due to clogging, failure, or other unforeseen circumstances that may occur once the measured pressure crosses setpoint for the PCV, the PCV control system 600b may command one or more of the PCV system valves 320 to open to the extent necessary to stabilize the wellbore pressure, divert the return mud from the annulus 108 to the MGS 155, vibrating screen 160, or others drilling fluid separation and purification systems. In this way, the wellbore pressure can be maintained within a safe pressure gradient, below the fracture pressure and above the formation pore pressure, without the need to actuate the PRV 175, disable the BOP 130, or take other drastic measures. Advantageously, the drilling crew is given the opportunity to investigate the root cause of the pressure problem while maintaining pressure in the wellbore and without compromising the structural integrity of the wellbore or personnel safety.

In FIG. 4 shows a hierarchical pressure control method 400 for controlled pressure drilling in accordance with one or more embodiments of the present invention. One of ordinary skill in the art will appreciate that software, including, for example, one or more hydraulic models and/or simulations, may provide models predicted safe pressure gradients, predicted wellbore pressure distributions with depth, and assumed target MPD pressure values, PCV set point and PRV set point before the actual drilling operation. The software may take into account the type and type of equipment used that forms part of the drilling rig, the type and type of well to be drilled, and information related to what is known about the soil through which the wellbore is to be drilled, as well as the drilling environment. These actions are usually taken before the start of drilling operations. After completion and prior to actual drilling operations, additional use of hydraulic models, simulations, and limit tests can be performed to debug models, predicted gradients, predicted pressure distributions, and setpoints.

Once the drilling operation has started, the hydraulic model can receive near real-time information from various equipment and sensors on the rig, and as the drilling operation progresses, the software can update its models, predicted pressure gradients, predicted pressure distributions, and setpoints continuously, periodically, or as needed. as more information becomes available. The hydraulic model will typically provide an MPD pressure setpoint corresponding to the desired wellhead back pressure, riser pressure, or model-based wellbore pressure within a safe pressure gradient, however the MPD pressure setpoint may be provided by the user. To achieve the MPD pressure set point, the MPD control system can command one or more inlet valves of an MPD inlet manifold to adjust the nozzle orifice setting of one or more inlet valves by the correct amount. When the measured pressure is maintained at a value approximately equal to the MPD pressure set point, drilling operations can be started or resumed, as appropriate.

At 410, one or more measured pressure values may be received by at least the MPD control system, the PCV control system, and the PRV control system. Each measured pressure value represents the result of an actual pressure measurement made by an integrated or separate pressure sensor that is part of the drilling system. Typically, with respect to wellhead backpressure measurement, the measured pressure value corresponds to a wellhead backpressure measurement taken at the wellhead, typically by a pressure transducer built into or in line with the MPD inline manifold. Pressure can be measured continuously, intermittently, or when a predefined event occurs. The measured pressure values can be transferred to the MPD control system, PCV control system,

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PRV or hydraulic model, which can be executed in one of the control systems or independently of them. In a hydraulic model, one or more of the model data, simulation data, and measured pressure data may be used on-line to calculate the MPD pressure setpoint to achieve the desired wellbore pressure for current operating conditions. The hydraulic model can provide the MPD pressure setpoint to the MPD control system. In response, the MPD control system may command one or more of the choke valves of the MPD choke manifold to go to the correct choke orifice setting that achieves the MPD pressure setpoint. However, unforeseen circumstances may occur that prevent the MPD in-line manifold from controlling pressure at a given MPD pressure, including, for example, clogging, failure, or other unforeseen circumstances affecting one or more in-line valves. Although one or more of the choke valves in an MPD choke manifold may have a self-cleaning function that attempts to remove debris that may restrict flow, these operations are not always successful. The MPD control system or the choke operator may be able to open additional choke valves or selectively select those choke valves that are not clogged and remain operational, however this may limit the ability of the MPD choke manifold to control wellbore pressure. Against this background, the method described in this document relates to hierarchical pressure control for MPD jobs.

At 420, if the measured pressure is greater than the MPD pressure setpoint, the control system may command one or more of the MPD inlet manifold valves to open as desired until the measured pressure is approximately equal to the MPD pressure setpoint, or one or more inlet manifold valves. MPD manifolds are commanded to go into a fully open choke setting corresponding to maximum flow capacity. Due to the difference between the measured pressure value and the MPD pressure setpoint, the hydraulic model can determine adjustments to the setting, or position, of the orifice of one or more MPD inlet manifold inlet valves that may be necessary to achieve the MPD pressure setpoint. However, one or more in-line MPD in-line manifold valves may experience plugging, failure, or other unforeseen circumstances. If the MPD control system instructs one or more of the choke valves in an MPD choke manifold to go to the setting, or fully open choke position, for maximum flow capability, and the measured pressure is still above the MPD pressure setpoint, an unforeseen circumstance occurs. where the MPD choke manifold alone can no longer safely control wellbore pressure within a safe pressure gradient. In conventional drilling systems, such an event would require a stop to drilling, actuation of the PRV, shutdown of the VOR, and other drastic measures that threaten the structural integrity of the wellbore and the ability to eventually resume drilling operations.

Advantageously, at 430, if at any time the sensed pressure exceeds the set value for the PCV, the MPD control system may place the MPD inline manifold into a standby mode such that it maintains its last position, often in a commanded fully open state, and the PCV control system can command one or more PCV valves to open until the measured pressure is less than the PCV setpoint, or command one or more PCV valves to go into a full open PCV setting. One or more valves in the PCV system can direct flow to MGS, vibrating screens, other mud separation and purification systems, or dump mud overboard in offshore applications. In some embodiments, the PCV setpoint may be determined by the hydraulic model as a value that is less than the PRV setpoint by a predetermined margin of safety sufficient to prevent the PRV from opening until the MPD inlet manifold and the PCV system are unable to control pressure in the wellbore. In other embodiments, the PCV setpoint may be automatically determined by the hydraulic model to be less than the PRV setpoint by a margin sufficient to allow one or more PCV valves to fully open before the measured pressure exceeds the PRV setpoint, partially by based on information about the type or types of choke valves and their ability to shed flow. In yet other embodiments, the PCV setpoint may be automatically determined by the hydraulic model based on the fracture pressure curve.

Advantageously, the PCV system can open an additional flow path to prevent further pressure increase and at the same time also prevent pressure drop in the wellbore. Once opened, the PCV system may attempt to keep the PCV setpoint as constant as possible with heavy clipping and control to enable fast response. If the pressure stabilizes at the PCV set point, the drilling crew may be able to investigate the root cause and attempt to correct the problem. If the problem is resolved, drilling operations can be resumed if the measured pressure can be maintained at a value approximately equal to the MPD pressure setpoint.

At 440, if at any time the sensed pressure exceeds the set value for the PRV, the PRV control system may command the PRV to open as a last resort. The set point for PRV can be determined by determining the lowest pressure value from a set of maximum operating pressures for the drilling system equipment. The set point for the PRV may be set to the lowest determined pressure value less than an optional predetermined safety margin. The setpoint for the PRV can be determined using one or more of the hydraulic models, simulation, or user input. Although the PRV, when open, protects the rig equipment from high pressure events, the pressure in the wellbore will drop until all system pressure is released, meaning that pressure is not maintained in the wellbore in within a safe pressure gradient may fall below the pore pressure and drastic measures such as turning off the BOP may be required to ensure well safety. As such, launching a PRV is considered a worst-case action only taken as a last resort when the MPD and PCV are unable to control wellbore pressure. The PRV can direct flow to MGS, vibrating screens or overboard in offshore applications. In one or more embodiments of the present invention, the non-volatile computer-readable medium contains software instructions that, when executed by a processor, can perform any of the above methods.

In FIG. 5A shows an illustrative plot of MPD choke position, wellhead back pressure, PCV setpoint, PCV setpoint, PRV setpoint, and PRV position when a PCV system is used to supplement an MPD choke manifold (e.g., 145 in FIG. 3) under pressure control. in the wellbore within a safe system pressure gradient (eg, 300 in FIG. 3) for the purpose of hierarchical pressure control for managed pressure drilling operations in accordance with one or more embodiments of the present invention.

In FIG. 5A and 5B show an example of how a hierarchical pressure control method and system for MPD jobs would handle the exemplary situation shown in FIG. 2A and 2B. Initially, the position of the MPD choke and the corresponding wellhead back pressure are relatively constant, which is to be expected during normal drilling operations. In the event that one or more choke valves in an MPD choke manifold (e.g., 145 in FIG. 3) begin to clog, fail, or have other unforeseen circumstances, wellhead backpressure may begin to rise for reasons other than intentionally closing one or several in-line valves of an MPD in-line manifold (for example, 145 in Fig. 3). The MPD control system (eg, 600a in FIG. 3) may respond to an increase in wellhead back pressure by commanding one or more choke valves of the MPD choke manifold (eg, 145 in FIG. 3) to open in an attempt to stabilize the pressure. However, even after one or more choke valves of the MPD choke manifold (e.g., 145 in FIG. 3) are commanded to go into a full-open choke setting corresponding to maximum flow capability, back pressure at the wellhead continues to rise. Once the wellhead backpressure exceeds the PCV set point, the PCV control system (for example, 600b in Figure 3) can command one or more valves in the PCV system (for example, 320 in Figure 3) to open to assist the choke manifold. MPD (eg, 145 in FIG. 3) in wellbore pressure control. In the illustrated example, the PCV (eg, 320 in FIG. 3) stops further pressure buildup and the pressure stabilizes at or near the PCV set point. At this point, rig personnel can investigate the root cause of the pressure problem while one or more valves in the PCV system (eg, 320 in FIG. 3) protect the structural integrity of the wellbore.

In continuation, in FIG. 5B shows an exemplary plot of pore pressure, fracture pressure, and wellbore pressure when one or more PCV system valves (eg, 320 in FIG. 3) are used to supplement an MPD choke manifold (eg, 145 in FIG. 3) while controlling pressure in wellbore within a safe system pressure gradient (eg, 300 in FIG. 3) for the purpose of hierarchical pressure control for managed pressure drilling operations in accordance with one or more embodiments of the present invention. As shown, a safe pressure gradient can be established by means of pore pressure (or collapse pressure in some cases) and fracture pressure. Initially, the wellbore pressure closely follows the pore pressure, but is slightly higher, but the well is within a safe pressure gradient. When one or more in-line valves of the MPD in-line manifold (for example, 145 in Fig. 3) begin to clog, exit

- 11 042987 failure or other unforeseen circumstances occur, the pressure in the wellbore begins to rise. As shown in FIG. 5A, the MPD control system (eg, 600a in FIG. 3) attempts to control wellbore pressure within a safe pressure gradient by opening one or more MPD choke manifold choke valves (eg, 145 in FIG. 3). However, an MPD choke manifold (eg, 145 in FIG. 3) alone cannot maintain wellbore pressure within a safe pressure gradient. Instead of actuating the PRV (for example, 175 in Fig. 3), the PCV control system (for example, 600b in Fig. 3) commands one or more valves of the PCV system (for example, 320 in Fig. 3) to open in an attempt to help the choke manifold MPD (eg, 145 in FIG. 3) in controlling wellbore pressure within a safe pressure gradient. When one or more valves in the PCV system (eg, 320 in FIG. 3) are opened, the wellhead back pressure (see FIG. 5A) stabilizes at or near the PCV setpoint and the wellbore pressure safely stabilizes at some pressure in within a safe pressure gradient. Advantageously, in contrast to the situation depicted in FIG. 2A and 2B, the wellbore pressure never exceeds the fracture pressure, never falls below the pore pressure, and the structural integrity of the wellbore is maintained without the need to actuate the PRV (eg, 175 in FIG. 3). Advantageously, rig personnel can investigate the root cause of the pressure problem while one or more valves in the PCV system (eg, 320 in FIG. 3) protect the structural integrity of the wellbore. After clarification of the reasons, you can resume the flow to the MPD choke manifold (for example, 145 in Fig. 3). As long as the pressure is controlled within a safe pressure gradient, drilling operations can continue.

In FIG. 6 shows a computer or control system 600 in accordance with one or more embodiments of the present invention. One skilled in the art will appreciate that, as discussed above, a hierarchical pressure control system for controlled pressure drilling (e.g., 300 in FIG. 3) may comprise a plurality of control systems (e.g., MPD control system 600a, PCV control system 600b or the PRV control system 600c) that operate independently of each other to the extent that the failure of one aspect of the hierarchical pressure control does not cause the failure of another aspect of the hierarchical pressure control, as a precaution to protect the drilling system, personnel on the drilling rig and the environment. Notwithstanding the foregoing, in some embodiments, such control systems, or the functions or features they implement, may be integrated or distributed, depending on the application or design, in accordance with one or more embodiments of the present invention. One of skill in the art will also appreciate that MPD control system 600a, PCV control system 600b, and PRV control system 600c may differ from one another and from application to application, depending on the application and design in accordance with one or more embodiments of the present inventions.

An exemplary computer or control system 600 may include one or more of a central processing unit (CPU) 605, a main bridge 610, an input/output (IO) bridge 615, a graphics processing unit (GPU) 625, an application specific integrated circuit (ASIC) (not shown). ) and a programmable logic controller (PLC) (not shown) located on one or more printed circuit boards (not shown) that perform computational or logic operations. Each CPU 605, GPU 625, ASIC (not shown), and PLC (not shown) may be a single-core device or a multi-core device. Multi-core devices typically comprise a plurality of cores (not shown) located on the same physical matrix (not shown) or a plurality of cores (not shown) located on a composite matrix (not shown) that are co-located in the same and the same mechanical block (not shown).

The CPU 605 may be a general purpose computing device, typically executing software instructions. The CPU 605 may include one or more of an interface 608 to the main bridge 610, an interface 618 to the system storage device 620, and an interface 623 to one or more IO devices, such as one or more GPUs 625, for example. a computing device that typically performs graphics functions related to framebuffer operation. However, one of ordinary skill in the art will appreciate that the GPU 625 can be used to perform non-graphics, computationally intensive functions. In some embodiments, GPU 625 may have an interface 623 directly with CPU 605 (and indirect interface 618 with system storage 620 via CPU 605). In other embodiments, GPU 625 may interface 621 directly with main bridge 610 (and indirectly interface 616 or 618 with system storage 620 via main bridge 610 or CPU 605, depending on the application or design). In yet other embodiments, the GPU 625 may have an interface 633 directly with the IO bridge 615 (and have an indirect interface 616 or 618 with the system storage device 620 via the main bridge 610 or CPU

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605 depending on application or design). One of skill in the art will appreciate that GPU 625 also includes on-board storage. The functionality of the GPU 625 may be integrated, in whole or in part, with the CPU 605 and/or the main bridge 610.

Master bridge 610 may be an interface device that implements an interface between one or more computing devices and IO bridge 615, as well as, in some embodiments, system storage 620. Master bridge 610 may include interface 608 to CPU 605, interface 613 to bridge 615 IO, for embodiments in which the CPU 605 does not contain an interface 618 to the system storage device 620, an interface 616 to the system storage device 620, and for embodiments in which the CPU 605 does not contain an integrated GPU 625 or an interface 623 to the GPU 625 , - interface 621 to GPU 625. The functionality of main bridge 610 may be integrated, in whole or in part, with CPU 605 and/or GPU 625.

An IO bridge 615 may be an interface device that interfaces between one or more computing devices and various IO devices (eg, 640, 645) as well as expansion or additional IO devices (not shown separately). An IO bridge 615 may include an interface 613 to a host bridge 610, one or more interfaces 633 to one or more IO expansion devices 635, an interface 638 to a keyboard 640, an interface 643 to a mouse 645, an interface 648 to one or more local storage devices 650, and interface 653 to one or more devices 655 network interface. The functionality of the IO bridge 615 may be integrated, in whole or in part, with the CPU 605 and/or the host bridge 610. Each local storage device 650, if present, may be a solid state storage device, an array of solid state storage devices, a hard disk drive, an array of hard disk drives or any other non-volatile machine-readable medium. The network interface device 655 may provide one or more network interfaces, including any network protocol suitable for facilitating network communication.

The control system 600 may include one or more network connected storage devices 660 in addition to or instead of one or more local storage devices 650 . Each network attached storage device 660, if present, may be a solid state storage device, an array of solid state storage devices, a hard disk drive, a hard disk drive array, or any other non-volatile computer-readable medium. Network connected storage device 660 may or may not be co-located with control system 600 and may be accessible to control system 600 through one or more network interfaces provided by one or more network interface devices 655 .

One of skill in the art will appreciate that control system 600 may be a conventional computing system or a dedicated computing system (not shown). In some embodiments, a dedicated computing system (not shown) may include one or more ASICs (not shown) or programmable logic controllers (PLCs) (not shown) that perform one or more special functions in a more efficient manner. One or more ASICs (not shown) may interface directly to the CPU 605, main bridge 610, or GPU 625, or interface through the IO bridge 615. Alternatively, in other embodiments, an application-specific computing system (not shown) may be reduced to only those components necessary to perform the required function or functions, in an attempt to reduce one or more of the number of integrated circuits, the area occupied by printed circuit boards, the amount of heat dissipation, and energy consumption. One or more ASICs (not shown) or PLCs (not shown) may be used in place of one or more of the CPU 605, main bridge 610, IO bridge 615, or GPU 625. In such systems, one or more ASICs (not shown) or PLCs (not shown) may have sufficient functionality to perform certain network, computing, or logic functions in a minimal footprint and significantly fewer component devices.

As such, one skilled in the art will appreciate that the CPU 605, main bridge 610, IO bridge 615, GPU 625, ASIC (not shown) or 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 application, design, or form factor, in accordance with one or more embodiments of the present invention. Thus, the description of control system 600 is illustrative only and is not intended to limit the type, form, or configuration of the component devices that make up control system 600 suitable for performing computing operations in accordance with one or more embodiments of the present invention. Notwithstanding the foregoing, one of skill in the art will appreciate that control system 600 may be industrial, stand-alone, laptop, desktop, server, ultra-compact server, server cabinet, and may vary depending on the application. or design.

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, hierarchical pressure control for MPD operations provides a multi-level hierarchical pressure control mode that complements the MPD choke manifold's ability to control wellbore pressure within a safe pressure gradient in a manner that protects the structural integrity of the wellbore when contingencies arise. with pressure.

In one or more embodiments of the present invention, hierarchical pressure control for MPD operations controls wellbore pressure within a safe pressure gradient even when severe pressure contingencies occur, giving rig personnel critical time to resolve a problem when without compromising the structural integrity of the wellbore.

In one or more embodiments of the present invention, hierarchical pressure control for MPD operations controls wellbore pressure within a safe pressure gradient even in the event of severe pressure contingencies without the need to activate a PRV, disable a BOP, or take other drastic measures.

In one or more embodiments of the present invention, hierarchical pressure control for MPD operations increases the life and efficiency of the drilling system by allowing operations to continue even in the event of major pressure contingencies.

In one embodiment of the present invention, hierarchical pressure control for MPD jobs improves job safety.

In one or more embodiments of the present invention, hierarchical pressure control for MPD operations protects the environment from pollution typically associated with the discharge of return drilling fluid overboard when the PRV is actuated.

Although the present invention has been described with respect to the above embodiments, those skilled in the art, having the benefit of this description, will appreciate that other embodiments may be devised that fall within the scope of the present invention as described herein. Accordingly, the scope of the present invention is to be limited only by the appended claims.

Claims (20)

1. The method of hierarchical pressure control for drilling operations under controlled pressure (MPD), including: receiving the measured pressure value; if the measured pressure is greater than the MPD pressure setpoint, commanding one or more choke valves of the MPD choke manifold to open until the measured pressure is approximately equal to the MPD pressure setpoint or a command is received to move to a fully open choke setting; if at any time the measured pressure exceeds the pressure control valve setpoint, put the MPD in-line manifold into standby mode and command one or more valves in the pressure control valve system to open until the measured pressure falls below the setpoint for the pressure control valve. pressure control valve or no command is received to go to the plant with the pressure control valve fully open; and if at any time the sensed pressure exceeds a predetermined value for the pressure relief valve, commanding the pressure relief valve to open. 2. The method of claim 1, further comprising receiving the MPD pressure setpoint from the hydraulic model. 3. The method of claim 1 further comprising commanding the MPD nozzle manifold to a set MPD pressure value. 4. The method according to claim 1, characterized in that it further comprises: determination of the lowest pressure value from the set of maximum operating pressures for the drilling system equipment; setting the setpoint for the pressure relief valve to the lowest pressure value less than a predetermined safety margin. 5. The method according to claim 1, characterized in that it further comprises determining the setpoint - 14 042987 for a pressure control valve that is below the pressure relief valve setpoint by a predetermined safety margin sufficient to prevent the pressure relief valve from opening. 6. The method of claim 1, further comprising automatically determining, using a hydraulic model, a setpoint for the pressure control valve based on the fracture pressure curve. 7. The method of claim 1 further comprising automatically determining, using the hydraulic model, a pressure control valve setpoint that is below the pressure relief valve setpoint by a margin sufficient to allow the pressure control valve to open fully before how the measured pressure exceeds the set value for the pressure relief valve. 8. The method of claim 1, further comprising starting the drilling operation when the measured pressure is maintained at a value approximately equal to the MPD pressure setpoint. 9. The method of claim 1 further comprising, after one or more valves of the pressure control valve system have been opened and the sensed pressure has been reduced to a value below a set value for the pressure control valve, resuming drilling operations when the sensed pressure is maintained at a value approximately equal to the set pressure MPD. 10. The method of claim 1, further comprising, if the sensed pressure falls below the MPD pressure set point, commanding the MPD manifold to close until the sensed pressure is approximately equal to the MPD pressure set point or A command has been received to move to a fully closed MPD in-line manifold. 11. Method according to claim 1, characterized in that the measured pressure value is received from a pressure sensor. 12. The method of claim 1, wherein one or more valves of the pressure control valve system direct flow to the mud gas separator. 13. The method of claim 1, wherein the pressure relief valve vents the flow overboard. 14. The method of claim 1, wherein the pressure relief valve directs flow to the mud gas separator. 15. The method of claim 1, wherein the pressure relief valve directs the flow into the vibrating screen. 16. The method of claim 1, wherein if the measured pressure falls outside the predetermined MPD pressure limits, the drilling operation is stopped and the rate of injection of the drilling fluid is maintained. 17. The method of claim 1, wherein if the sensed pressure falls outside the predetermined pressure limits of the pressure control valves, the well is secured on the blowout prevention device. 18. A non-volatile computer-readable medium containing software instructions that, when executed by the processor, allow the execution of a sequence of operations in accordance with the method of claim 1. 19. A hierarchical pressure control system for drilling under controlled pressure, comprising: an annular sealing system that provides an annular seal surrounding the drill string; a pressure sensor that measures pressure; an MPD choke manifold comprising a plurality of choke valves, wherein at least one choke valve is in fluid communication with a flow line that removes return drilling fluid from or below the annulus seal to apply back pressure to the wellhead; an MPD control system that commands one or more in-line valves of the in-line MPD manifold to open when a sensed pressure exceeds a preset MPD pressure value; one or more pressure control valves, wherein at least one pressure control valve is in fluid communication with a flow line discharging return drilling fluid to a drilling fluid gas separator, vibrating screen, or other drilling fluid separation and purification system; a pressure control valve control system that commands one or more pressure control valves to open if, at any time, a sensed pressure exceeds a predetermined value for the pressure control valve; a pressure relief valve that vents the return mud into the mud gas separator, vibrating screen, or overboard; and a pressure relief valve control system that commands the pressure relief valve to open if, at any time, the sensed pressure exceeds a set value for the pressure relief valve. 20. The system according to claim 19, characterized in that the MPD control system, the pressure control valve control system and the pressure release valve control system are independent.