METHOD FOR SAFE DYNAMIC AUTOMATIC PASSAGE TRANSFER BETWEEN MANAGED PRESSURE DRILLING AND WELL CONTROL AND NON-TRANSIENT COMPUTER-READABLE MEDIUM
Patent Information
- Application Number
- BR112022022791
- Authority / Receiving Office
- BR · BR
- Patent Type
- Patents
- Current Assignee / Owner
- Publication Date
- 2026-09-08
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Abstract
Description
1 / 41 METHOD FOR SAFE DYNAMIC AUTOMATIC PASSAGE TRANSFER BETWEEN MANAGED PRESSURE DRILLING AND WELL CONTROL AND NON-TRANSIENT COMPUTER-READABLE MEDIUM BACKGROUND OF THE INVENTION
[0001] Managed pressure drilling (MPD) techniques seek 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 ring surrounding the drill string, and surface backpressure is controllably applied by manipulating the choke opening setting, sometimes called the choke position, of one or more choke valves in an MPD choke tubing located on the drilling rig. The MPD choke tubing is fluidly connected to one or more flowlines that divert return fluid from the annular valve or its underside to the surface.Each choke valve has the capacity for a fully open state where flow is free, a fully closed state where flow is interrupted, and numerous intermediate states where flow is at least partially restricted. Thus, if the pressure in the ring is below a lower limit, one or more choke valves in the MPD choke piping can be closed as needed to increase the annular pressure by the required amount. Similarly, if the pressure in the ring rises above an upper limit, one or more choke valves in the MPD choke piping can be opened as needed to decrease the annular pressure by the required amount. Petition 870220103921, dated 09 / 11 / 2022, page 9 / 134 2 / 41 required. In practice, MPD systems are used in one of several operating modes. In surface backpressure mode, the surface backpressure in the MPD choke tubing is directly managed. In bottomhole pressure mode, a hydraulic model is used to calculate a pressure that will achieve a desired depth pressure based on models, real-time data, and the operation being conducted. Regardless of the operating mode, the means by which pressure is managed is the manipulation of one or more choke valves in the MPD choke tubing.
[0002] During certain drilling operations, MPD can be used to maintain well control by managing the wellbore pressure within a safe pressure gradient bounded by pore pressure and fracture pressure, with collapse pressure sometimes being used in place of pore pressure if it is greater than pore pressure. In this context, well control generally refers to the techniques used to manage hydrostatics and formation pressure to prevent the unintentional influx of unknown formation fluids into the wellbore system. If the pressure in the annulus is 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 termed a kick.Chutes are inherently dangerous due to the fact that unknown formation fluids may contain explosive gas, increasing the risk of a dangerous explosion. Similarly, if the pressure in the ring rises above the fracture pressure, a. Petition 870220103921, dated 09 / 11 / 2022, p. 10 / 134 3 / 41 The formation can fracture hydraulically or break apart, causing drilling fluids to be lost to the formation. If the fluid level within the wellbore decreases to the point where the wellbore pressure is below the pore pressure, then a kick can occur and well control can be lost. Therefore, standard industry practices aim to maintain well control during drilling and other operations through careful navigation of the safe pressure gradient. However, geological uncertainties, inaccurate information, and constantly changing conditions sometimes lead to unexpected contingencies, and it is extremely important to have the ability to take appropriate action when a kick occurs.Thus, once a kick occurs, if the kick volume and the additional pressure required to exterminate the well exceed a predetermined operational limit, MPD operations are interrupted and well control operations are manually performed to circulate out the unknown formation fluids in the well system to restore well control so that drilling operations can be safely resumed. BRIEF SUMMARY OF THE INVENTION
[0003] According to one aspect of one or more embodiments of the present invention, a method of safe dynamic automatic passage transfer between pressure-managed drilling and well control includes setting a pressure setpoint of an MPD choke pipe to a surface backpressure setpoint and setting a pressure setpoint of an automatic well control choke pipe to a detected pressure measured from the bottom of a preventer. Petition 870220103921, dated 09 / 11 / 2022, page 11 / 134 4 / 41 of eruption or a line pressure switch of the eruption preventer. A pressure imbalance is created by setting the pressure setpoint of the MPD choke piping above the pressure setpoint of the automatic well control choke piping by a predetermined amount. The pressure imbalance automatically causes an MPD control system to close the MPD choke piping while the control system for well control opens the automatic well control choke piping.The method further includes verifying that the detected pressure or the interrupt line pressure increases until the automatic well control choke piping opens sufficiently for the blowout preventer pressure or interrupt line pressure to remain constant, closing a blowout preventer ring after the MPD choke piping is closed, and diverting unknown formation fluids from the blowout preventer choke line to the automatic well control choke piping for delivery to a mud and gas separator. The wellbore remains fluidically dynamic due to the continuous injection of drilling fluids.
[0004] According to one aspect of one or more embodiments of the present invention, a non-transient computer-readable means comprises software instructions that, when executed by a processor, perform a method of safe dynamic automatic throughput transfer between pressure-managed drilling and well control that includes setting a pressure setpoint of an MPD choke pipe to a backpressure setpoint of Petition 870220103921, dated 09 / 11 / 2022, page 12 / 134 5 / 41 surface and set a pressure setpoint on an automatic well control choke pipe to a detected pressure measured from the bottom of a blowout preventer or a blowout preventer line pressure switch. A pressure imbalance is created by setting the MPD choke pipe pressure setpoint above the automatic well control choke pipe pressure setpoint by a predetermined amount. The pressure imbalance automatically causes an MPD control system to close the MPD choke pipe while the well control system opens the automatic well control choke pipe.The method further includes verifying that the detected pressure or breakout line pressure increases until the automatic well control choke piping opens sufficiently for the blowout preventer pressure or breakout line pressure to remain constant, closing a blowout preventer ring after the MPD choke piping is closed, and diverting unknown formation fluids from the blowout preventer choke line to the automatic well control choke piping for delivery to a mud and gas separator. The wellbore remains fluidically dynamic due to the continuous injection of drilling fluids.
[0005] According to one aspect of one or more embodiments of the present invention, a system for safe dynamic automatic passage transfer between pressure-managed drilling and well control includes an annular sealing system capable of sealing in such a way as to Petition 870220103921, dated 09 / 11 / 2022, p. 13 / 134 6 / 41 controllable a ring surrounding a drill string that forms an annular MPD seal, a blowout preventer capable of controllably sealing a ring surrounding the drill string that forms a well control annular seal, an MPD choke piping 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 the MPD annular seal or its underside to a fluid processing system, an automatic well control choke piping 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 the well control annular seal or its underside to a mud and gas separator,It is a control system for well control that automates the settings of the automatic well control throttling piping during automatic throughput transfers between pressure-managed drilling and well control operations to maintain the wellbore in a fluid dynamic state.
[0006] Other aspects of the present invention will become apparent from the following description and claims. BRIEF DESCRIPTION OF THE DRAWINGS
[0007] FIGURE 1 shows a conventional closed-loop hydraulic drilling system for pressure-managed drilling operations and conventional well control.
[0008] FIGURE 2 shows an improved closed-loop hydraulic drilling system for transfer of Petition 870220103921, dated 09 / 11 / 2022, page 14 / 134 7 / 41 Safe dynamic automatic transition between pressure-managed drilling and well control according to one or more embodiments of the present invention.
[0009] FIGURE 3 shows an exemplary control system according to one or more embodiments of the present invention. DETAILED DESCRIPTION OF THE INVENTION
[0010] 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 detailed description of the present invention that follows, specific details are set forth in order to provide a complete understanding of the present invention. In other cases, features well known to a person of ordinary skill in the art are described to avoid obscuring the description of the present invention. For purposes of clarity, for the wellbore components described herein, top or upper refers to a portion or side that is closest, directly or with reference to another component, to the surface above the wellbore and bottom or lower refers to a portion or side that is closest, directly or with reference to another component, to the bottom of the wellbore.
[0011] FIGURE 1 shows a conventional closed-cycle hydraulic drilling system 100 for conventional MPD and well control operations. For illustrative purposes, a drilling system 100 for offshore drilling operations is shown. Since offshore applications require additional components such as, for example, a marine riser system, to facilitate drilling a Petition 870220103921, dated 09 / 11 / 2022, page 15 / 134 8 / 41 Subsea well hole, a person of ordinary skill in the art will recognize that onshore, or land-based, applications are substantially similar in configuration and function to those components required for conventional MPD and well control operations. Therefore, the following description applies with equal force to land-based drilling systems that include conventional MPD and well control capabilities.
[0012] The drilling system 100 includes a drilling rig 101, in this case, a semi-submersible type drilling rig disposed in a body of water 102, which includes various equipment configured to drill a subsea well hole 106 below the seabed 104 to recover hydrocarbons disposed therein. A person of ordinary skill in the art will observe that the type or kind of drilling rig may vary based on the application. In deepwater applications, the seabed 104 may be more than 300 meters (1000 feet) below the surface of the water 102. In ultra-deepwater applications, the seabed 104 may be 1500 meters (5000 feet) or more below the surface of the water 102.The drilling system 100 may include an MPD system (e.g., annular seal system 110, annular closure system 115, and return flow spool 120), a marine riser system 125, and a blowout preventer (BOP) 130, in the offshore example depicted, a subsea BOP (SSBOP). A person of ordinary skill in the art will recognize that the drilling system 100 may include other components such as, for example, a last resort diverter (not shown), a ball joint (not shown), and a telescopic joint (not shown) which are typically disposed above the system. Petition 870220103921, dated 09 / 11 / 2022, page 16 / 134 9 / 41 MPD, which are not shown or necessary for understanding the discussion that follows.
[0013] For high specification drilling systems 100, the MPD System typically includes an annular seal system 110, an annular closure system 115 disposed below the annular sealing system 110, and a return flow spool 120 disposed below the annular closure system 115. The annular sealing system 110 controllably seals the ring 108 that surrounds the drill string. 135 so that it is encapsulated. The annular sealing system 110 may be a Rotation Control Device (RCD), an Active Control Device (ACD), or any other type or kind of system capable of creating a ring seal so that wellbore pressure can be controlled by applying surface backpressure. The annular closure system 115 is a redundant system to maintain the ring seal when the annular closure system 110, or components thereof, are being installed, repaired, or replaced. The return flow spool 120 diverts return fluids from the ring seal or from the bottom of the same to the MPD choke pipe 145 which directs the return fluids to the fluid processing system (e.g., MGS 155 or shale agitators 160) for recycling and reuse.The return flow spool 120 is disposed above, and in fluid communication with, the lower portion of the marine riser system 125. A person with ordinary skill in the art will recognize that, in low-specification drilling systems, one or more of the components mentioned above may be combined or omitted, but all MPD systems require at least one of these systems. Petition 870220103921, dated 09 / 11 / 2022, page 17 / 134 10 / 41 annular closure disposed above the BOP 130 and means to controllably divert return fluids from the ring seal or from the bottom thereof.
[0014] 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 bundle connector (LMRP) (unlabeled), an upper ring preventer 126, a lower ring preventer 127, one or more blind cut-off gates 128, one or more casing cut-off gates 129, an upper variable hole gate 131, a lower variable hole gate 132, and a wellhead connector (unlabeled). The switch line 124 fluidly connects one or more mud pumps (e.g., 170) disposed on the surface to the SSBOP 130 to inject fluids below the ring of SSBOP 130 during conventional well control operations described in more detail in this document. The choke line 133 fluidly connects an SSBOP outlet. 130 below the ring to a well control choke pipe 134 arranged on the surface to catch fluid returns through the choke line 133 during conventional well control operations, also described in more detail in this document. The SSBOP 130 is arranged above, and in fluid communication with, a wellhead (not illustrated independently) which is arranged above and in fluid communication with a wellbore 106 that is drilled. A central lumen extends through the conventional MPD system (e.g., annular seal system 110, annular closure system 115, and return flow spool 120), marine riser system 125, SSBOP 130, wellhead Petition 870220103921, dated 09 / 11 / 2022, page 18 / 134 11 / 41 of the well (not shown independently) and into wellbore 106 to facilitate drilling and other operations. The drill string 135 can be disposed through the central lumen and includes, at one distal end, a downhole or drill bit assembly 140 configured to drill wellbore 106.
[0015] During MPD operations, such as continuation drilling, one or more mud pumps 170 controllably pumps drilling fluids (not shown) from the mud tank 165 inside the well through an inside passage of the drill string 135. The return fluids (not shown) return through the ring 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 shown separately) of the MPD choke piping 145.One or more throttle valves of MPD 145 throttle piping controllably flows through flow line 147 to flowmeter 150, and flowmeter 150 flows through flow line 153 to one or more fluid processing systems including, for example, MGS 155 and / or shale agitators 160 for processing before returning the processed fluids (not shown) to the slurry tank 165 for reuse. One or more pressure sensors (not shown) are arranged in the fluid path at different locations to measure the pressure of the return fluids (not shown).
[0016] The MPD 190 control system can receive pressure sensor data and flowmeter 150 data in real time or approximate time. A person with average skill in the technique Petition 870220103921, dated 09 / 11 / 2022, page 19 / 134 12 / 41 will recognize that real or approximate time means very close to the moment of measurement, delayed by measurement, calculation, and / or transmission only, but typically on the order of magnitude of mere fractions of a second or seconds. The MPD 190 control system can command one or more choke valves (not independently illustrated) of the MPD 145 choke piping to a desired choke position and / or command the flow rate of mud pumps 170, to achieve a desired pressure. The tight pressure seal on the ring provided by the annular seal system 110 allows precise control of wellbore pressure by manipulating the choke position of one or more choke valves (not independently illustrated) of the MPD 145 choke piping and applying the corresponding surface backpressure.The throttling position of one or more throttling valves (not independently illustrated) of the MPD 145 throttling tubing corresponds to an amount, typically represented as a percentage, that one or more throttling valves (not independently illustrated), or the MPD 145 throttling tubing itself, is open and capable of flow. If the throttling operator wishes to increase wellbore pressure, the throttling position of one or more throttling valves (not independently illustrated) of the MPD 145 throttling tubing may be reduced to further restrict fluid flow and apply additional surface backpressure. Similarly, if the throttling operator wishes to decrease wellbore pressure, the throttling position of one or more throttling valves may be reduced. Petition 870220103921, dated 09 / 11 / 2022, page 20 / 134 13 / 41 The throttling (not independently illustrated) of the MPD 145 throttling tubing can be increased to increase fluid flow and reduce the amount of applied surface backpressure. Thus, MPD systems typically manage wellbore pressure by manipulating the throttling position of one or more throttling valves (not independently illustrated) of the MPD 145 throttling tubing and / or the flow rate of mud pumps 170 that inject fluids into the well, based at least on pressure sensor data.
[0017] In certain applications, a hydraulic model (not shown independently) can be used during MPD and other operations to calculate wellbore pressure, or equivalent circular density (ECD), in near real-time or approximate time based on wellbore, equipment, and sensor data including, but not limited to, one or more of the following: well depth, casing depth, bore diameter, tilt angles, water depth, riser diameter, drill string configuration, geothermal gradient, hydrothermal gradient, real-time drilling parameters such as flow rate, spin rate, block position (or drill depth), block velocity and mud properties, and in-hole or surface-based sensor data that provide actual measurements of various parameters in near real-time or approximate time.ECD refers to the effective density exerted by a circulating fluid against the formation, taking into account the pressure drop in the ring above the point being considered. Therefore, ECD can be considered the wellbore pressure expressed in terms of equivalent pressure. Petition 870220103921, dated 09 / 11 / 2022, page 21 / 134 14 / 41 weight of mud at a given depth. During drilling operations, the use of ECD is typically preferred over the use of wellbore pressure, as the latter is more descriptive for those operating the drill bit; however, a person with common skill in the technique will recognize that they are alternative representations of the same concept and can be used interchangeably with simple conversion. The MPD system can be operated in one of several operating modes. During drilling and other operations, the MPD system can be used to perform what is termed surface backpressure control. In this operating mode, the throttling position of one or more throttling valves of the MPD 145 throttling pipe can be adjusted, directly or automatically, to achieve a desired pressure in the MPD 145 throttling pipe above the surface.However, the MPD system can also be used to manage pressure within the well. In this mode of operation, the hydraulic model can be used to calculate the pressure, and the programmable logic controller (PLC) of the MPD 190 control system can determine the throttling position of one or more throttling valves in the MPD 145 throttling piping to achieve the calculated pressure inside the well at depth, considering the particularities of the wellbore, equipment, and sensor data.
[0018] As noted above, during conventional MPD operations, drilling fluids are pumped through the inner passage of the drill string 135, out of the drill bit 140, and then return. Petition 870220103921, dated 09 / 11 / 2022, page 22 / 134 15 / 41 through ring 108. Drilling fluids cool and lubricate the drill bit 140, wash downhole cuts, and balance formation pressure. Return fluids are typically processed over the surface, and drilling fluids are separated and recycled for reuse within the well. Since wellbore pressure is effectively managed, under normal operating conditions, the outflow of return fluids is substantially equal to the inflow of drilling fluids. Thus, there is no substantial loss of drilling fluids to the formation and no substantial influx of unknown formation fluids into the wellbore. However, due to geological uncertainties, kicks sometimes occur during continued drilling. Kicks can be identified, for example, by an imbalance where outflow exceeds inflow for a period of time.When a kick is detected during continued drilling, the MPD system is the first piece of equipment used to respond. Upon detecting the kick, the MPD control system will initiate the closure of the MPD 145 choke pipe to apply additional pressure to the well in order to suppress the kick formation, sometimes referred to as well kill. 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 is made as to whether the volume of formation fluids obtained during the kick requires well control operations. The driller will typically input the total kick volume with the additional pressure required to balance the formation into an operating matrix that determines whether the inflow... Petition 870220103921, dated 09 / 11 / 2022, page 23 / 134 16 / 41 can be circulated out of the well through the MPD system. If the total kick volume exceeds the operational array, regulations, equipment technical limits, or agreed limits regarding what can be circulated out through the MPD system, then a decision is made to resort to manually performed well control operations to circulate the kick out through the well control throttling piping 134 under a closed BOP 130. It is important to recognize that MPD operations are sometimes conducted under automation and the determination to resort to well control operations requires the intervention of a human operator to make the decision to resort, as well as to manually perform the subsequent well control operations.
[0019] Once the decision is made to circulate the kick out through manually performed well control operations, a first transition, or automatic through-handle transfer, is performed from MPD operations to conventional well control operations. The mud pumps 170 are switched off, drill string rotation 135 is stopped, and the MPD choke line 145 is closed to maintain bottomhole pressure, resulting in the first static condition with respect to fluids within the wellbore 106, meaning there is no fluid circulation within it during this time period. This is the first of two times the wellbore becomes static during automatic through-handles transfers. Then, the BOP 130 is closed, via the ring 126 or 127 or gate 128, 129, 131, or 132, and the choke line 133 is pressed against the Remote valve. Petition 870220103921, dated 09 / 11 / 2022, page 24 / 134 17 / 41 The Hydraulically Controlled (HCR”) (not shown) valve of BOP 130 is then opened, allowing returns to be made through the choke line 133. The mud pumps 170 are then switched back on and ramped up to start injecting drilling fluids through the drill string 135, while manually adjusting the choke position of the well control choke pipe 134 in an attempt to regulate pressure inside the well while taking turns through the choke line 133, based on pressure measurements taken at the well control choke pipe 134 or at BOP 130.Pressure regulation inside the well is manually controlled, typically by a choke operator who adjusts the choke position of the well control choke pipe 134 until the pressure at the stop line 124, as measured on the surface, or the pressure at the BOP 130, as measured underwater by a sensor (not shown), is constant. A person with ordinary skill in the art will observe that measuring the pressure at the BOP 130 is preferable; however, in systems lacking such a sensor (not shown), the pressure at the stop line 124 can be used. The choke operator turns a physical handwheel or, in electronically controlled flow chokes, manually pushes a button up or down on an industrial control system (not shown) while monitoring the pressure at the stop line 124 or BOP 130 to achieve stability.
[0020] After establishing the desired mud pump speed of 170, the throttle operator manipulates the throttle position of one or more pipeline valves. Petition 870220103921, dated 09 / 11 / 2022, page 25 / 134 18 / 41 of well control choke 134, maintaining constant cane pipe pressure, until the kick is circulated out of wellbore 106. The density of return fluids is constantly measured at the surface. Whenever the density of return fluids is substantially equal to the density of injected fluids (i.e., meaning there are no remaining explosive gases in the return fluids), the kick volume has been circulated out of wellbore 106 and the well control operation is complete. At this point, a second automatic handover is performed, this time from well control operations to MPD, so that the MPD system can resume drilling.Mud pumps 170 are shut off again and well control choke piping 134 is closed while mud pumps 170 are shut off, so that when mud pumps 170 are completely stopped, well control choke piping 134 is completely closed. This represents the second static condition with respect to the fluids within wellbore 106, since circulation has been interrupted. The pressure inside the well is maintained at a constant pressure at the shut-off line 124 or below the BOP 130 seal while mud pumps 170 are slowed down. The marine riser 125 is then pressurized to equalize pressure through BOP 130, then BOP 130 is opened. The HCR valve (not shown separately) is closed after mud pumps 170 are stopped or after pressure is equalized through BOP 130, at the driller's discretion.Circulation is then re-established by starting the mud pumps 170, injecting drilling fluids through the drill string 135, and taking turns through the flow line 122 from the... Petition 870220103921, dated 09 / 11 / 2022, page 26 / 134 19 / 41 return flow reel 120. The MPD 145 choke pipe is then re-engaged to manage wellbore pressure 106 during drilling operations, typically under automation.
[0021] While MPD operations are generally automated, meaning that the hydraulic model is used to calculate the desired pressure and the MPD control system 190 determines the appropriate throttling position of one or more throttling valves of the MPD throttling piping 145 to achieve the desired pressure, conventional well control operations are performed manually, including the decision to resort to well control operations. During the first automatic handover, from MPD operations to conventional well control operations, the mud pumps 170 are stopped and the wellbore 106 becomes fluidically static below the BOP 130 for the first time. During a substantial portion of the well control operations, the kick volume is manually circulated out of the wellbore 106.Again, during the second automatic handover, from conventional well control operations to MPD operations, the mud pumps 170 are stopped and the wellbore 106 becomes fluidically static for the second time. In both cases, the fluidically static state of the wellbore causes the formation of gels. When the fluids within wellbore 106 become static, there are solids in the wellbore fluid mixture, and these solids react, creating what is known in the industry as gels. Gels are undesirable because they tend to create pressure spikes during the startup of the mud pumps 170, in addition to the fact that they create... Petition 870220103921, dated 09 / 11 / 2022, page 27 / 134 20 / 41 difficulty in transmitting pressure through the wellbore system as required for precise pressure management within wellbore 106. Therefore, every time circulation is interrupted and wellbore 106 becomes static, gels are formed and additional force needs to be applied to break the gel reactions and reduce friction.
[0022] Consequently, in one or more embodiments of the present invention, the safe dynamic automatic handover between MPD and well control operations provides, for the first time, the ability to automate MPD operations, well control, and transitions between them, which keeps the wellbore in a fluid dynamic state at all times, increasing the reliability, efficiency, and safety of operations. In the case of a kick, a safe automatic handover from MPD to well control operations is performed without ever becoming static 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; and a safe automatic handover from well control to MPD operations is also performed without ever becoming static with respect to the fluids within the wellbore.Advantageously, since the wellbore remains dynamic even during automatic through-hole transfers, gel formation is prevented, thus preventing pressure spikes during mud pump startup. Additionally, pressure transmission is improved, allowing for more precise pressure management during all phases of MPD operations, well control operations, and transitions between them. Petition 870220103921, dated 09 / 11 / 2022, page 28 / 134 21 / 41
[0023] FIGURE 2 shows an enhanced closed-loop hydraulic drilling system 200 with an automatic well control choke pipe 234 for safe dynamic automatic through-pass transfer between MPD and well control operations according to one or more embodiments of the present invention. Safe dynamic automatic through-pass transfer means an automatic through-pass transfer or transition between MPD and well control or well control and MPD wherein the wellbore remains fluidically dynamic due to continuous injection of drilling fluids. For illustrative purposes, a drilling system 200 for offshore drilling operations is shown.Since offshore applications require additional components such as, for example, a marine riser system, to facilitate the drilling of a subsea well hole, a person with ordinary skill in the art will recognize that onshore, or land-based, applications are substantially similar in configuration and function with respect to those components required for MPD and well control operations. Therefore, the following description applies with equal force to land-based drilling systems that include MPD and well control capabilities.
[0024] The drilling system 200 may include an automatic well control choke pipe 234, a control system for independent well control 290, and optionally a downstream flowmeter 250 that allows automation of automatic through-pass transfer and well control operations as discussed in more detail in this document. Similar to the conventional well control choke pipe 134 of FIGURE Petition 870220103921, dated 09 / 11 / 2022, page 29 / 134 22 / 41 1. The automatic well control throttling pipe 234 can obtain fluid returns from the throttling line 133 below the BOP seal 130. An optional flowmeter 250 can be arranged downstream of the automatic well control throttling pipe 234 and fluidly connect the automatic well control throttling pipe 234 to the mud and gas separator 155. The control system for independent well control 290 can automatically control the throttling position of one or more throttling valves of the automatic well control throttling pipe 234 during automatic through-transfers between pressure-managed drilling and well control operations and during well control operations to maintain the wellbore in a fluid dynamic state at all times.In configurations that include the optional 250 flowmeter, the 250 flowmeter can provide sensor data to the control system for 290 well control.
[0025] The automatic well control choke pipe 234 may be substantially similar to conventional well control choke pipe (e.g., 134 of FIGURE 1) in terms of core choke functionality, but differs in that it includes an interface that allows independent control by the well control system 290. The well control system 290 and the automatic well control choke pipe 234 may include connectivity that facilitates control of the choke pipe 234 by the well control system 290. Thus, the well control system Petition 870220103921, dated 09 / 11 / 2022, page 30 / 134 23 / 41 well 290 can dictate the throttling position of the automatic well control throttling piping 234. For example, software running on the control system for well control 290, or a related system, can manage operations of the automatic well control throttling piping 234, including commanding one or more throttling valves of the automatic well control throttling piping 234 to a desired throttling position to achieve a desired surface pressure or wellbore pressure. Considering for the purpose of the present discussion that the drilling system 200 is drilling using the MPD system (e.g., annular seal system 110, annular closure system 115, and return flow spool 120), potentially under automation. Due to geological uncertainties, a kick may occur unexpectedly.When a kick is detected, the MPD system may be the first piece of equipment used to respond to the contingency. Upon detecting the kick, the MPD control system may begin closing one or more choke valves on the MPD 145 choke piping to apply additional pressure to the flywheel in order to suppress kick formation. For example, under automation, the MPD 190 control system may begin closing one or more choke valves on the MPD 145 choke piping 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 outflow is substantially equal to inflow, a determination can be made as to whether the volume of unknown formation fluids obtained during the... Petition 870220103921, dated 09 / 11 / 2022, page 31 / 134 A 24 / 41 kick requires well control operations. The driller will typically place the total kick volume with the additional pressure required to balance the formation into an operating matrix to determine if unknown formation fluids can be circulated out of the well through the MPD system. If the total kick volume exceeds the operating matrix, regulations, equipment technical limits, or agreed-upon limits on what can be circulated out through the MPD system, then a decision is made to resort to well control operations.
[0026] 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 out the volume of unknown formation fluids within the wellbore 106. In this way, the MPD system can be used to apply additional surface backpressure to the well while the mud pumps 170 are operating. The inflow and outflow can be monitored to identify if the well 106 enters losses such that the inflow exceeds the outflow. The result of the DFIT is a determination of the pressure range that the formation presents integrally. The higher the pressure, the higher the speed of the mud pump 170 that can be used, provided that the choke line friction 133 is not exceeded when doing so.Ideally, the preference is to fully open the fluid path through the automatic well control throttling tubing 234 to shorten the time required to circulate the kick volume out.
[0027] At this point, the kick was obtained, it was Petition 870220103921, dated 09 / 11 / 2022, page 32 / 134 25 / 41 determined that the kick needs to be circled out using well control operations, and the MPD system was used to terminate the well. The MPD system is in wellbore pressure mode where the hydraulic model is used to calculate the wellbore pressure. With this information, the PLC choke (not shown independently) of the MPD control system 190 determines whether the pressure setpoint of the MPD choke pipe 145 on the surface needs to be increased or decreased to achieve the desired wellbore pressure, thereby regulating the wellbore pressure through the application of surface backpressure.The drill string rotation can be stopped, or significantly reduced, then the drill string can be moved away, so that the drill string 135 is moved up or down, typically up, since the drill bit 140 is likely over the bottom surface of the hole 106 in the continuation of drilling, to ensure that there is no tool binding in the path of the blind cutting gates 128 or the pipe gates 129, 131, and 132. Then, the rotation of the drill string 135 and the intensifier are stopped. The real-time hydraulic model can calculate the friction loss in the flywheel 106 and, since the MPD system is in wellbore pressure mode, the MPD control system 190 can automatically adjust the throttling position of one or more MPD throttling pipe 145 throttling valves to compensate for the change.The drilling fluid injection rate can be reduced to the maximum flow rate for the automatic well control choke pipe 234. If the DFIT. Petition 870220103921, dated 09 / 11 / 2022, page 33 / 134 26 / 41 indicates that sufficient flow is possible; it may be possible to leave the Pressure During Drilling (PWD) tool on. This can be simulated before future simulations to determine the friction contribution of choke line 133 with sufficient flow rate to keep the PWD tool active. At this point, the MPD system may be regulating with surface pressure. With the automatic well control choke piping 234 completely closed at this point, the HCR valve (not independently shown) can be opened, which can be verified by a pressure increase in kill lines 124 and choke 133. Although differences in pressures of kill lines 124 and choke 133 can be expected due to possible differences in mud weight and temperature between marine riser 125 and lines 124 and 133, the differences need to make sense and need to be of the same order of magnitude.
[0028] At this point, returns can potentially be taken by either MPD choke tubing 145 or automatic well control choke tubing 234, and automatic well control choke tubing 234 is regulating with a detected pressure measured from the bottom of the BOP 130 or line pressure switch 124. However, standard industry practice is to isolate marine riser 125 from wellbore 106 for safety reasons. In order to automatically begin closing MPD choke tubing 145 while automatic well control choke tubing 234 opens, a small pressure imbalance is created between the tubing of Petition 870220103921, dated 09 / 11 / 2022, page 34 / 134 27 / 41 MPD 145 choke and automatic well control choke piping 234, which causes the MPD 190 control system to automatically close one or more valves of the MPD 145 choke piping. For example, the MPD 190 control system may set the pressure set point of the MPD 145 choke piping to a value higher than the pressure set point of the automatic well control choke piping 234 by a predetermined amount, such as, for example, 0.3 MPa (50 pounds per square inch) (psi). A person with ordinary skill in the art will recognize that the predetermined amount may vary based on the application or design.Next, verify that the detected pressure measured from the bottom of BOP 130 or switch line 124 increases until the automatic well control choke pipe 234 begins to open as needed to maintain the pressure of BOP 130 or switch line 124 constant. For example, the control system for well control 290 begins to open the automatic well control choke pipe 234 as needed to maintain the pressure of BOP 130 or switch line 124 constant. The MPD flowmeter 150 will likely experience a loss since the optional well control flowmeter 250, if included, will exhibit a substantially equivalent gain. When the MPD choke pipe 145 is fully closed, all wellbore returns 106 can flow through the automatic well control choke pipe 234.At this point, BOP 130 can be closed via ring 126 or 127 or gate 128, 129, 131 or 132. Return fluids can be routed from the line of... Petition 870220103921, dated 09 / 11 / 2022, page 35 / 134 28 / 41 choke 133 and from BOP 130 to the automatic well control choke piping 234 for delivery to the mud and gas separator 155. Advantageously, the entire process, including continued drilling with MPD, detecting the kick, making the automatic through-pass transfer from the MPD system to well control, and performing well control operations, is done with the wellbore remaining in a fluidically dynamic state below BOP 130, with consistent fluid injection. With the isolated marine riser 125, the MPD control system 190 can monitor potential gas within the riser 125 and, if gas is present, it can be circulated out using the MPD system.
[0029] Similarly, once well control operations are completed, the automatic handover of well control operations to the system MPDs can be performed without ever remaining static with respect to the wellbore fluids. For the transition from well control operations to MPDs, the choke piping of MPD 145 can be used to pressurize marine riser 125 to equalize pressure across BOP 130. Once equalized, BOP 130 can be opened and the automatic well control choke piping 234 can be operated in a mode that seeks to manage the pressure in BOP 130. In order to automatically begin closing the automated well control choke piping 234 while the MPD 145 choke piping opens, a small pressure imbalance can be created between the automatic well control choke piping 234 and the MPD 145 choke piping. For example, a control system for well control. Petition 870220103921, dated 09 / 11 / 2022, page 36 / 134 29 / 41 290 can set a pressure set point for the automatic well control choke piping 234 to a value higher than the pressure set point for the MPD choke piping 145 by a predetermined amount, such as, for example, 0.3 MPa (50 psi). A person with ordinary skill in the art will recognize that the predetermined amount may vary based on the application or design. Then, verify that the detected pressure measured from the bottom of the annular shut-off system 110 increases until the MPD choke piping 145 begins to open as needed to maintain the pressure below the annular shut-off system 110 constant. For example, the MPD control system 190 begins to open the MPD choke piping 145 as needed to maintain the pressure below the annular shut-off system 110 constant.The optional well control flowmeter 250, if present, will observe a loss as the MPD flowmeter 150 will display an equivalent gain during the transition whereby the well control choke pipe 234 closes while the MPD choke pipe 145 opens. When the automatic well control choke pipe 234 is fully closed, the HCR valve (not independently illustrated) can be closed and all wellbore returns 106 can flow through the MPD choke pipe 145. At this point, MPD operations, including continued drilling, can be resumed.
[0030] A person of ordinary skill in the technique, having the benefit of the present disclosure, will recognize that the steps indicated above can be performed in a different order based on one or more of the procedures of Petition 870220103921, dated 09 / 11 / 2022, page 37 / 134 30 / 41 operator, driller or rig. A person with ordinary skill in the art will recognize that safe dynamic automatic through-flow transfer between MPD and well control maintains wellbore fluids in a dynamic state. The methods disclosed in this document allow for the safe transition of MPD for well control and from well control to MPD in a way that does not require mud pumps to be stopped, thus ensuring a fluidically dynamic state in the wellbore that advantageously prevents gel formation.
[0031] FIGURE 3 shows an exemplary computer or control system 300 according to one or more embodiments of the present invention. A person of ordinary skill in the art will recognize that, as discussed above, a system for safe dynamic automatic passage transfer between MPD and well control (e.g., 200 of Figure 2) may include a plurality of control systems (e.g., MPD control system 190, well control system 290, and others not necessarily shown) that operate independently of each other from a device perspective, but may optionally work together systemically to achieve the objectives of the safe dynamic automatic passage transfer method disclosed herein.Notwithstanding the foregoing, in certain embodiments, such control systems, or the functions or resources they implement, may be integrated or distributed based on an application or design in accordance with one or more embodiments of the present invention. A person of ordinary skill in the art will also recognize the type or kind of MPD 190 control system and well control system 290. Petition 870220103921, dated 09 / 11 / 2022, page 38 / 134 31 / 41 may vary from one to another, and from application to application, based on an application or design according to one or more embodiments of the present invention.
[0032] An exemplary computer or control system 300 may include one or more of a Central Processing Unit (“CPU”) 305, a host bridge 310, a bridge of Input / Output (“I / O”) 315, Graphics Processing Unit (“GPUs”) 325, Application-Specific Integrated Circuit (“ASIC”) (not shown), and Programmable Logic Controller (“PLC”) (not shown) arranged on one or more printed circuit boards (not shown) that perform computational or logical operations. Each CPU 305, GPU 325, ASIC (not shown), and PLC (not shown) may be a single-core device or a 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).
[0033] A CPU 305 can be a general-purpose computing device that executes software instructions. A CPU 305 may include one or more of the following interfaces: 308 for host bridge 310, 318 for system memory 320, and 323 for one or more I / O devices, such as, for example, one or more GPUs 325. A GPU 325 can serve as a specialized computing device that typically performs graphics functions related to the manipulation of temporary frame storage. However, a person with average skill in the art will recognize that a GPU 325 can be Petition 870220103921, dated 09 / 11 / 2022, page 39 / 134 32 / 41 used to perform computationally intensive non-graphics functions. In certain embodiments, the GPU 325 can interface 323 directly with the CPU 305 (and indirectly interface 318 with system memory 320 through the CPU 305). In other embodiments, the GPU 325 can interface 321 directly with the host bridge 310 (and indirectly interface 316 or 318 with system memory 320 through the host bridge 310 or CPU 305 depending on the application or project). In still other embodiments, the GPU 325 can interface 333 directly with the I / O bridge 315 (and interface 316 or 318 indirectly with system memory 320 through the host bridge 310 or CPU 305 depending on the application or project). A person with average skill in the art will recognize that GPU 325 includes integrated memory as well. In certain configurations, the functionality of the GPU 325 can be integrated, fully or partially, with the CPU 305 and / or host bridge 310.
[0034] The host bridge 310 may be an interface device that interfaces between one or more computing devices and I / O bridges 315 and, in some embodiments, system memory 320. The host bridge 310 may include interface 308 with the CPU 305, interface 313 with the I / O bridge 315, for embodiments where the CPU 305 does not include interface 318 with system memory 320, interface 316 with system memory 320, and for embodiments where the CPU 305 does not include an integrated GPU 325 or interface 323 with the GPU 325, interface 321 with the GPU 325. The functionality of the host bridge 310 may be integrated, fully or partially, with the CPU 305 and / or the GPU 325.
[0035] The I / O bridge 315 can be a device Petition 870220103921, dated 09 / 11 / 2022, p. 40 / 134 33 / 41 interface that interfaces between one or more computing devices and various I / O devices (e.g., 340, 345) and I / O expansion, or add-on devices (not independently illustrated). The I / O bridge 315 may include interface 313 with host bridge 310, one or more interfaces 333 with one or more I / O expansion devices 335, interface 338 with keyboard 340, interface 343 with mouse 345, interface 348 with one or more local storage devices 350, and interface 353 with one or more network interface devices 355. The functionality of the I / O bridge 315 may be integrated, wholly or partially, with the CPU 305, host bridge 310, and / or GPU 325. Each local storage device 350, if any, may be a solid-state memory device, an array of solid-state memory devices, a hard disk drive, an array of hard disk drives, or any non-transient computer-readable media.The 355 network interface device can provide one or more network interfaces, including any suitable network protocol, to facilitate network communications.
[0036] The control system 300 may include one or more network-attached storage devices 360 in addition to, and in place of, one or more local storage devices 350. Each network-attached storage device 360, if any, may be a solid-state memory device, an array of solid-state memory devices, a hard disk drive, an array of hard disk drives, or any other non-transient computer-readable media. The network-attached storage device 360 may or may not be located with the control system 300 and may be accessible to the control system 300. Petition 870220103921, dated 09 / 11 / 2022, page 41 / 134 34 / 41 through one or more network interfaces by one or more network interface devices 355.
[0037] A person with ordinary skill in the art will recognize that the control system 300 may be a conventional computing system or an application-specific computing system (not shown) configured for industrial applications. In certain embodiments, an application-specific computing system (not shown) may include one or more ASICs (not shown) PLCs (not shown) that perform one or more specialized functions in an efficient manner. The one or more ASICs (not shown) may interface directly with the CPU 305, host bridge 310, or GPU 325 or interface via I / O bridge 315. Alternatively, in other embodiments, an application-specific computing system (not shown) may represent a reduced number of components that are needed to perform a desired function or functions in an effort to reduce one or more chip counts, printed circuit board volume, thermal design power, and power consumption. In many embodiments, one or more ASICs (not shown) and / or PLCs (not shown) may be used in place of one or more 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, computational, or logic functions in a minimum volume with substantially fewer component devices.
[0038] Thus, a person with average skill in the technique will recognize that CPU 305, host bridge 310, bridge of Petition 870220103921, dated 09 / 11 / 2022, page 42 / 134 35 / 41 I / O 315, GPU 325, ASIC (not shown), or PLC (not shown), or a subset, superset, or combination of functions or features thereof, may be integrated, distributed, or excluded, wholly or in part, based on the application, design, or form factor according to one or more embodiments of the present invention. Thus, the description of the control system 300 is merely illustrative and is not intended to limit the type, kind, or configuration of component devices that constitute a control system 300 suitable for performing computational operations according to one or more embodiments of the present invention. Notwithstanding the foregoing, a person of ordinary skill in the art will recognize that the control system 300 may be an industrial, standalone, laptop, desktop, server, blade, or rack-mountable system and may vary based on application or design.
[0039] In one or more embodiments of the present invention, a method of safe dynamic automatic flow transfer between pressure-managed drilling and well control may include identifying an unintentional influx of unknown formation fluids into a wellbore. One or more valves in the MPD choke piping may close until the pressure inside the well is sufficient to suppress further influx of unknown formation fluids into the wellbore, sometimes termed wellbore kill. After the kick is taken, a determination may be made as to whether the volume of unknown formation fluids and the additional pressure inside the well required to suppress further influx exceed an operating matrix or limit. If it exceeds, Petition 870220103921, dated 09 / 11 / 2022, page 43 / 134 36 / 41 The kick volume requires outward circulation through the well control choke tubing, and a safe dynamic automatic through-through transfer from MPD to well control may include an initial transition that maintains a fluidically dynamic state with respect to the wellbore fluids. In certain embodiments, an optional DFIT test may be performed to determine the maximum pump speed that can be used to circulate out the unknown formation fluid volume within the wellbore while the formation remains intact. After this, the drill string may be moved away to ensure there is no tool binding in the path of a blind shear drawer of the blowout preventer.An MPD choke pipe pressure setpoint can be set to a surface backpressure setpoint, and an automatic well control choke pipe pressure setpoint can be set to a detected pressure measured from the bottom of a blowout preventer or a blowout preventer line pressure switch. The drilling fluid injection rate can be reduced to maximize the flow rate through the automatic well control choke pipe.A pressure imbalance can be created by setting the pressure setpoint of the MPD choke piping above the pressure setpoint of the automatic well control choke piping by a predetermined amount, so that the pressure imbalance automatically causes the MPD control system to close the MPD choke piping while the control system for well control opens the choke piping. Petition 870220103921, dated 09 / 11 / 2022, page 44 / 134 37 / 41 Automatic Well Control Choke Pipe. The detected pressure or switch line pressure can be detected to verify that it increases until the automatic well control choke pipe opens sufficiently so that the blowout preventer pressure or switch line pressure remains constant. Then, after the MPD choke pipe has been completely closed, a blowout preventer ring can be closed. The blowout preventer HCR valve can then be opened to allow flow through the blowout preventer choke line. Unknown formation fluids can be diverted from the blowout preventer choke line to the automatic well control choke pipe for delivery to a mud and gas separator.Throughout this entire process, the wellbore remains fluidically dynamic due to the continuous, but not necessarily the same, velocity of the drilling fluid injection. In certain embodiments, a flowmeter may be placed downstream of the automatic well control choke pipe. A determination can be made regarding whether unknown formation fluids have been circulated out of the wellbore by a substantial equivalence in fluid density between outflow and inflow. During the transition, as well as during well control operations, the wellbore remains fluidically dynamic. In certain embodiments, including offshore applications, gas-containing fluids may be in the marine riser. If there is gas within the now-isolated marine riser, unknown formation fluids may be circulated out of the riser. Petition 870220103921, dated 09 / 11 / 2022, page 45 / 134 38 / 41 marine using MPD choke tubing.
[0040] Once unknown formation fluids are safely circulated out of the wellbore and potentially the marine riser in offshore applications, a safe dynamic automatic well control to MPD through-through transfer can include a second transition that also maintains a fluidically dynamic state with respect to the wellbore fluids. In offshore applications, the marine riser can be pressurized to equalize pressure across the blowout preventer. Continuing, in all applications, the blowout preventer ring can be opened. The pressure setpoint of the automatic well control choke piping can be set at the detected pressure measured from the bottom of the blowout preventer or the blowout preventer line pressure switch.A second pressure imbalance can be created by setting the pressure setpoint of the automatic well control choke piping above the pressure setpoint of the MPD choke piping by a second predetermined amount, wherein the second pressure imbalance automatically causes the well control system to close the automatic well control choke piping while the MPD control system opens the MPD choke piping. The second predetermined amount can be less than, equal to, or greater than the predetermined amount used to create the pressure imbalance during the first MPD to well control transition. Then, the blowout preventer HCR valve can be closed after the well control choke piping has been closed. The borehole. Petition 870220103921, dated 09 / 11 / 2022, page 46 / 134 39 / 41 of the well remains fluidically dynamic due to the continuous rate, but not necessarily the same rate of drilling fluid injection. At this point, the MPD system can be used for continued drilling once again. In certain embodiments, the operation of both MPD and well control operations, including transitions between them, can be automated. While a human operator typically makes the decision regarding circulating fluids out through the MPD system or the well control system, all other steps can be performed by the MPD control system, well control system, and potentially a computer running the hydraulic model.A person with ordinary skill in the art will recognize that a non-transient computer-readable medium comprises software instructions that, when executed by a process, can perform one or more of the methods indicated above in accordance with one or more embodiments of the present invention.
[0041] Advantages of one or more embodiments of the present invention may include one or more of the following:
[0042] In one or more embodiments of the present invention, the safe dynamic automatic flow transfer 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 wellbore in a dynamic fluid state at all times, thereby increasing the reliability, efficiency and safety of operations.
[0043] In one or more embodiments of the present invention, the safe dynamic automatic passage transfer between MPD and well control provides, for the first time Petition 870220103921, dated 09 / 11 / 2022, page 47 / 134 40 / 41 times, an automatic well control throttling pipe capable of regulating based on pressure at the throttling position to maintain the wellbore in a fluid dynamic state during transitions between MPD and well control operations.
[0044] In one or more embodiments of the present invention, the safe dynamic automatic through-transfer between MPD and well control manages the transitions from MPD to well control and from well control to MPD, wherein each transition is fluidically dynamic with respect to the fluids within the wellbore, advantageously preventing gel formation.
[0045] In one or more embodiments of the present invention, the safe dynamic automatic flow transfer between MPD and well control ensures that unknown formation fluids within the wellbore are contained and circulated out of the wellbore in a safe and efficient manner, without ever remaining static relative to the wellbore fluids.
[0046] In one or more embodiments of the present invention, the safe dynamic automatic flow transfer between MPD and well control prevents the formation of gels, thereby preventing pressure spikes during mud pump startup.
[0047] In one or more embodiments of the present invention, the safe dynamic automatic transfer between MPD and well control enhances pressure transmission through the well system, thereby enabling pressure management during all phases of MPD, well control operations, and transitions between them. Petition 870220103921, dated 09 / 11 / 2022, page 48 / 134 41 / 41 while maintaining a fluidically dynamic state within the wellbore.
[0048] In one or more embodiments of the present invention, the safe dynamic automatic flow transfer between MPD and well control increases the safety of operations by precisely managing pressure during all phases of MPD, well control and transitions between them.
[0049] In one or more embodiments of the present invention, the safe dynamic automatic flow transfer between MPD and well control maintains a dynamic fluid state with respect to the fluids within the wellbore even though rotation has been interrupted, preventing reactions that form gels that need to be vigorously broken up to resume MPD operations, such as continued drilling.
[0050] Although the present invention has been described with respect to the embodiments indicated above, those skilled in the art, having the benefit of the present disclosure, will recognize that other embodiments may be developed which are within the scope of the invention as described herein. Consequently, the scope of the invention shall be limited only by the appended claims. Petition 870220103921, dated 09 / 11 / 2022, page 49 / 134
Claims
1 / 11 CLAIMS 1. METHOD OF SAFE DYNAMIC AUTOMATIC PASSAGE TRANSFER BETWEEN MANAGED PRESSURE DRILLING AND WELL CONTROL, characterized by comprising: setting a pressure setpoint of an MPD choke pipe (145) to a surface backpressure setpoint; setting a pressure setpoint of an automatic well control choke pipe (234) to a detected pressure measured from below a blowout preventer (130) or a line pressure switch (124) of the blowout preventer (130);create a pressure imbalance by setting the pressure setpoint of the MPD choke pipe (145) above the pressure setpoint of the automatic well control choke pipe (234) by a predetermined amount, wherein the pressure imbalance automatically causes the MPD control system (190) to close the MPD choke pipe (145) while a control system for well control (290) opens the automatic well control choke pipe (234); verify that the detected pressure or line interrupter pressure (124) increases until the automatic well control choke pipe (234) opens sufficiently so that the blowout preventer pressure (130) or line interrupter pressure (124) remains constant; close the blowout preventer (130) after the MPD choke pipe (145) is closed;and divert unknown formation fluids from a Petition 870260067466, dated 08 / 07 / 2026, page 6 / 32 2 / 11 choke line (133) from the blowout preventer (130) to the automatic well control choke pipe (234) for delivery to a mud and gas separator (155), wherein the wellbore (106) remains fluidly dynamic due to the continuous injection of drilling fluids.; 2. METHOD, according to claim 1, characterized by comprising: identifying an unintentional influx of unknown formation fluids into the wellbore (106).
3. METHOD, according to claim 2, characterized by further comprising: closing one or more valves of the MPD choke pipe (145) until the pressure inside the well is sufficient to suppress further influx of unknown formation fluids into the wellbore (106).
4. METHOD, according to claim 3, characterized by further comprising: determining whether a volume of unknown formation fluids and the pressure within the well that is sufficient pressure to suppress further influx exceeds an operational limit that allows influx circulation through the MPD choke tubing (145).
5. METHOD, according to claim 4, characterized by further comprising: performing a Dynamic Formation Integrity Test to determine a maximum mud pump velocity (170) that can be used to circulate out the volume of unknown formation fluids within the wellbore (106).
6. METHOD, according to claim 5, Petition 870260067466, dated 08 / 07 / 2026, page 7 / 32 3 / 11 characterized by further comprising: interrupting rotation and outward displacement of a drill string (135) to ensure that there is no tool binding in a trajectory of a blind shear drawer or a blowout preventer tube drawer (130).
7. METHOD, according to claim 6, characterized by further comprising: interrupting the intensifier while the MPD throttling pipe (145) compensates for a friction loss.
8. METHOD, according to claim 7, characterized by further comprising: reducing a drilling fluid injection rate to maximize a flow rate through the automatic well control choke pipe (234).
9. METHOD, according to claim 8, characterized by further comprising: opening a Remote Hydraulic Control Valve of the eruption preventer (130) that generates flow through the throttling line (133) of the eruption preventer (130).
10. METHOD, according to claim 9, characterized by further comprising: completely closing the MPD choke pipe (145).
11. METHOD, according to claim 1, characterized by further comprising: monitoring potential gas within an isolated marine riser (125).
12. METHOD, according to claim 11, characterized by further comprising: if there is gas inside the isolated marine riser (125), Petition 870260067466, dated 08 / 07 / 2026, page 8 / 32 4 / 11 circulating fluids out of the marine riser (125) using the MPD choke pipe (145).
13. METHOD, according to claim 1, characterized by further comprising: monitoring a flow rate of return fluids downstream of the well control choke pipe (234).
14. METHOD, according to claim 1, characterized by further comprising: determining that the volume of unknown formation fluids was circulated out of the wellbore (106) by an equivalence in fluid density between outflow and inflow.
15. METHOD, according to claim 1, characterized by further comprising: pressurizing a marine riser (125) to equalize pressure across the blowout preventer (130); opening the blowout preventer (130); setting the pressure setpoint of the automatic well control choke piping (234) to the detected pressure measured from the bottom of the blowout preventer (130) or the line pressure switch (124) of the blowout preventer (130); create a second pressure imbalance by setting the pressure setpoint of the automatic well control throttling pipe (234) above the pressure setpoint of the MPD throttling pipe (145) by a second predetermined amount, wherein the second pressure imbalance automatically causes the well control system (290) to close Petition 870260067466, dated 08 / 07 / 2026, page.9 / 32 5 / 11 automatic well control throttling pipe (234) while the MPD control system (190) opens the MPD throttling pipe (145); and close a Hydraulically Controlled Remote valve of the blowout preventer (130) after the well control throttling pipe (234) is closed, wherein the wellbore (106) remains fluidically dynamic due to the continuous injection of drilling fluids.
16. METHOD, according to claim 1, characterized by further comprising: opening the eruption preventer (130); setting the pressure setpoint of the automatic well control throttling pipe (234) to the detected pressure measured from the bottom of the eruption preventer (130) or the line pressure switch (124) of the eruption preventer (130);create a second pressure imbalance by setting the pressure setpoint of the automatic well control choke pipe (234) above the pressure setpoint of the MPD choke pipe (145) by a second predetermined amount, wherein the second pressure imbalance automatically causes the well control system (290) to close the well control choke pipe (234) while the MPD control system opens the MPD choke pipe, closing a Hydraulically Controlled Remote valve of the blowout preventer (130) after the well control choke (234) is closed, wherein the wellbore (106) remains fluidically dynamic due to the continuous injection of drilling fluids.
17. NON-TRANSIENTIAL COMPUTER-READABLE MEDIUM, characterized by comprising instructions which, when executed by a processor, perform a method of secure dynamic automatic through-pass transfer between managed pressure drilling and well control comprising: setting a pressure setpoint of an MPD choke pipe (145) to a surface backpressure setpoint; setting a pressure setpoint of an automatic well control choke pipe (234) to a detected pressure measured from the bottom of a blowout preventer (130) or a blowout preventer (130) line pressure switch (124);Create a pressure imbalance by setting the pressure setpoint of the MPD choke pipe (145) above the pressure setpoint of the automatic well control choke pipe (234) by a predetermined amount, wherein the pressure imbalance automatically causes an MPD control system (190) to close the MPD choke pipe (145) while a control system (290) for well control opens the automatic well control choke pipe (234); verify that the detected pressure or line interrupter pressure (124) increases until the automatic well control choke pipe (234) opens sufficiently so that the blowout preventer pressure (130) or line interrupter pressure (124) remains constant; close the blowout preventer (130) after the pipe Petition 870260067466, dated 08 / 07 / 2026, page. 11 / 32 7 / 11 MPD choke (145) to be closed;and divert unknown formation fluids from a choke line (133) of the blowout preventer (130) to the automatic well control choke pipe (234) for delivery to a mud and gas separator (155), wherein the wellbore (106) remains fluidically dynamic due to the continuous injection of drilling fluids.; 18. 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 wellbore (106).
19. NON-TRANSIENT COMPUTER READABLE MEANS, according to claim 18, characterized in that the method further comprises: closing one or more valves of the pressure-managed drilling throttling pipe (145) until the pressure within the wellbore is sufficient to further suppress influx of unknown formation fluids into the wellbore (106).
20. NON-TRANSIENT COMPUTER READABLE MEANS, according to claim 19, characterized in that the method further comprises: determining whether a volume of unknown formation fluids and the pressure within the well that is sufficient pressure to suppress further influx exceeds an operational limit that allows influx circulation through the MPD choke tubing (145).
21. NON-TRANSIENT COMPUTER READABLE MEDIUM, of Petition 870260067466, of 08 / 07 / 2026, page 12 / 32 8 / 11 according to claim 20, characterized by the method further comprising: performing a Dynamic Formation Integrity Test to determine a maximum mud pump velocity (170) that can be used to circulate out the volume of unknown formation fluids within the wellbore (106).
22. NON-TRANSIENT COMPUTER READABLE MEANS, according to claim 21, characterized by the method further comprising: interrupting rotation and outward displacement of a drill string (135) to ensure that there is no tool binding in a trajectory of a blind shear drawer or a burst preventer tube drawer (130).
23. NON-TRANSIENT COMPUTER READABLE MEDIUM, according to claim 22, characterized in that the method further comprises: interrupting the intensifier while the MPD throttling pipe (145) compensates for a friction loss.
24. NON-TRANSIENT COMPUTER-READABLE MEANS, according to claim 23, characterized in that the method further comprises: reducing a drilling fluid injection rate to maximize a flow rate through the automatic well control choke tubing (234).
25. NON-TRANSIENT COMPUTER-READABLE MEANS, according to claim 24, characterized by the method further comprising: opening a Remote Hydraulic Control Valve of the eruption preventer (130) that generates flow through the choke line (133) of the eruption preventer (130). Petition 870260067466, dated 08 / 07 / 2026, page 13 / 32 9 / 11 26. NON-TRANSIENT COMPUTER READABLE MEDIUM, according to claim 25, characterized by the method further comprising: completely closing the MPD choke pipe (145).
27. NON-TRANSIENT COMPUTER-READABLE MEDIUM, according to claim 17, characterized by the method further comprising: monitoring potential gas within an isolated marine riser (125).
28. NON-TRANSIENT COMPUTER READABLE MEANS, according to claim 27, characterized in that the method further comprises: if there is gas inside the isolated marine riser (125), circulating the fluids out of the marine riser (125) using the MPD choke pipe (145).
29. NON-TRANSIENT COMPUTER READABLE MEANS, according to claim 17, characterized in that the method further comprises: monitoring a flow rate of return fluids downstream of the well control choke pipe (234).
30. NON-TRANSIENT COMPUTER READABLE MEDIUM, according to claim 17, characterized by the method further comprising: determining that the volume of unknown formation fluids was circulated out of the wellbore (106) by an equivalence in fluid density between outflow and inflow.
31. NON-TRANSIENTIAL COMPUTER-READABLE MEANS, from Petition 870260067466, dated 08 / 07 / 2026, page 14 / 32 10 / 11 according to claim 17, characterized by the method further comprising: pressurizing a marine riser (125) to equalize pressure across the eruption preventer (130); opening the eruption preventer (130); setting the pressure setpoint of the automatic well control choke pipe (234) to the detected pressure measured from the bottom of the eruption preventer (130) or the pressure of the eruption preventer (130) switch line (124);to create a second pressure imbalance by setting the pressure setpoint of the automatic well control throttling pipe (234) above the pressure setpoint of the MPD throttling pipe (145) by a second predetermined amount, wherein the second pressure imbalance automatically causes the well control system (290) to close the automatic well control throttling pipe (234) while the MPD control system (190) opens the MPD throttling pipe (145); and to close a Hydraulically Controlled Remote valve of the blowout preventer (130) after the well control throttling pipe (234) is closed, wherein the wellbore (106) remains fluidically dynamic due to the continuous injection of drilling fluids.
32. NON-TRANSIENT COMPUTER-READABLE MEANS, according to claim 17, characterized by the method further comprising: opening the eruption preventer (130); setting the pressure setpoint of the automatic well control throttling pipeline (234) to the detected pressure measured from the bottom of the eruption preventer (130) or the eruption preventer (130) line switch pressure;to create a second pressure imbalance by setting the pressure setpoint of the automatic choke pipe (234) above the pressure setpoint of the blowout preventer choke pipe (145) by a second predetermined amount, wherein the second pressure imbalance automatically causes the well control system (290) to close the automatic well control choke pipe (234) while the MPD control system (190) opens the MPD choke pipe (145) and closes a Hydraulically Controlled Remote blowout preventer valve (130) after the well control choke pipe (234) is closed, wherein the wellbore (106) remains fluidically dynamic due to the continuous injection of drilling fluids. Petition 870260067466, dated 08 / 07 / 2026, page 16 / 32;