RIG INTEGRATED MANAGED PRESSURE DRILLING SYSTEM AND METHOD

Abstract

The present disclosure provides a managed pressure drilling method and system that accommodates timely and accurate control of surface pressure in order to maintain appropriate wellbore pressure of a well. The system and method can use a minimal set of inputs, such as a measured pressure input, with a control software hierarchy described herein to improve the accuracy of the controlled pressure and automation of drilling rig components over conventional Managed Pressure Drilling (MPD) systems. Because the method compensates for the real pressure rate of change using the pressure input, the method and system allow the implementation of MPD techniques in legacy applications and drilling rigs. The system and method can reduce human error and inefficiencies that directly degrade the quality of MPD techniques and improve wellbore drilling and hydrocarbon production performance within the industry.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application Ser. No. 63/427,557, entitled “Rig Integrated Managed Pressure Drilling System and Method”, filed Nov. 23, 2022, which is incorporated herein by reference.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO APPENDIX

Not applicable.

BACKGROUND OF THE INVENTION

Field of the Invention

The disclosure generally relates to managed pressure drilling systems and methods. More specifically, the disclosure relates to managed pressure drilling systems and methods associated with drilling rig control systems.

Description of the Related Art

FIG. 1 is an illustrative system with surface components for drilling a subterranean borehole. FIG. 2 is an illustrative diagram of a typical hydrocarbon well and subterranean components for drilling a borehole in accordance with FIG. 1. FIG. 3 is an illustrative typical chart of a typical drilling window for a hydrocarbon well and salient subterranean pressures. FIG. 4 is an illustrative typical chart of wellbore pressures conventionally operating within a drilling window in accordance with FIG. 3 and principles disclosed herein. Subterranean boreholes are typically referred to as wells. Wells are drilled with a drilling rig 101, which is positioned within proximity to a subterranean reservoir such that a drill string 102 with a drill bit 201 on the bottom can be lowered into the desired drilling location through a blowout preventer (BOP stack) 103 connected to a wellhead on the ground at the surface of the well.

Typical wells in the oil and gas industry are drilled to produce hydrocarbons from a subterranean reservoir 202. While drilling, fluid or mud is pressurized by mud pumps and circulated through a top drive 105 into the drill string 102 (where the top drive hoists and rotates the drill string), through the drill bit nozzles 203, into the borehole space disposed between the drill string and a sidewall of a borehole, known as the annulus 204, and back to the surface. From there, the drilling fluid along with cuttings and other downhole miscellanea, known as well “returns”, briefly accumulate in a bell nipple 106 before being gravity-fed through a flow line 107 to a plurality of filtering systems before returning to the mud tanks 108 where the circulation cycle began. Drilling fluid is employed for several essential reasons, including removing the pieces of rock, known as “cuttings”, from the well during the drilling process, lubricating the subterranean drilling components and borehole to lessen the required forces and torques required to drill the borehole, and subterranean (or downhole) pressure control.

In the subsurface, there are two distinct pressures. The force exerted on the rock is referred to as “lithostatic pressure” (or “overburden pressure”). “Formation pressure” 301 is the force exerted on the liquids within the pores of the rock. The weight of the overlying rock exerts pressure on the fluids in the pores of underlying rock. As the reservoir is buried, it may compact in response to increased overburden pressure. By reducing porosity and forcing fluid out of the pore spaces, the reservoir contracts. “Hydrostatic pressure”, the pressure exerted by a fluid at rest due to gravity, remains constant as a result. If fluids cannot be expelled from the reservoir, the reservoir will not compact, and the pressure of the overlying rocks is transferred to the fluid.

Because the drilling fluid is in contact with the subterranean formations as it is circulated up the annulus 204, it exerts a pressure against the formations, known as “wellbore pressure” 401. Conventional drilling practices dictate a continuous overbalanced condition, meaning the wellbore pressure 401 is greater than the formation pressure 301. This prevents formation fluids from entering the wellbore, known as an influx or a “kick.” Conversely, too great of a wellbore pressure may fracture the formation, a threshold known as the fracture pressure 302, causing drilling fluid losses. The pressure range between formation pressure 301 and fracture pressure 302 is generally known as the “drilling window” 303.

The primary means of maintaining wellbore pressure within the drilling window 303 include, but are not limited to, intentionally controlling the density of the drilling fluid, known as “mud weight,” and manipulating operating surface parameters like the fluid volume pump rate from the mud pumps 104, generally referred to as “flow rate.” While circulating, the sum of the friction in the annulus 204 caused by the physical contact of the circulating fluid with the physical outer bounds of the annulus 204 and any object or obstruction inside the annulus 204 in addition to the hydrostatic pressure imposed by the fluid column of drilling mud creates an effective density known as the “Equivalent Circulating Density” (ECD) 402, which is the wellbore pressure while circulating. When more drill string 102 is needed to drill deeper, the top drive 105 is disconnected from the drill string 102 in order to pick up more tubulars to add to the drill string 102. As the top drive 105 is disconnected from the drill string 102, any pressure or fluid is prevented from flowing out of the open conduit on top of the drill string 102 by a check valve 205, commonly referred to as a “float.” This process is generally referred to as “making a connection.” During this time, circulation must stop, which due to the loss of the pressure created by the friction of the fluid while circulating in the annulus 204, the wellbore pressure reverts to roughly equal the hydrostatic pressure exerted by the mud weight, which can be referred to as “Equivalent Mud Weight” (EMW) 403. This change in Bottom Hole Pressure (BHP) 404, the pressure at the bottom of the wellbore at the most recently drilled formation, is demonstrated in FIG. 4.

Even if both the ECD 402 and EMW 403 remain within the drilling window 303, which is typically desirable, the difference in wellbore pressure between the ECD 402 and EMW 403 exerts a repetitive stress on the wellbore, which may begin to weaken the exposed rocks of the formation, leading to undesirable conditions related to wellbore instability including but not limited to hole collapse, stuck pipe, and drilling fluid losses, which, if present, are typically inevitable while conventionally drilling in areas prone to wellbore instability. Furthermore, the magnitude of undesirable pressure conditions can further be exacerbated by a plurality of uncontrollable natural phenomena including but not limited to the compressibility of the fluid and formations, thermal conductivity of the drilling fluid, drilling components, and formations, the introduction of extraneous formation fluids with varying properties, the tortuosity of the borehole, and non-empirical fluid mechanics.

FIG. 5 is an illustrative typical chart of wellbore pressure conventionally operating outside the bounds of a narrow drilling window in accordance with principles disclosed herein. While it is still desirable for both the ECD 402 and EMW 403 to exert pressure on the well within the drilling window 303, despite possibly inevitable undesirable conditions, this is not always achievable by conventional means. FIG. 5 illustrates ECD 402 and EMW 403 during conventional drilling through a narrow drilling window 303. In this example, the ECD 402 exceeds the fracture pressure 302 at the narrow drilling window 303, resulting in potential drilling fluid losses and excessive formation damage 501. Also in this example, the EMW 403 is exceeded by the formation pressure 301 at the narrow drilling window 303, resulting in a potential formation fluid influx 502. Typically, when both the ECD 402 exceeds the fracture pressure 302 and the EMW 403 falls below the formation pressure 301, Managed Pressure Drilling (MPD) is required to successfully drill the well.

FIG. 6 is an illustrative typical Managed Pressure Drilling system with surface components for conducting operations of drilling a subterranean borehole. Managed Pressure Drilling (MPD) techniques employ a method of directly controlling the pressure in the annulus 204, shown in FIG. 2, by manipulating pressure at the surface 206 of the annulus. This is performed by replacing the conventional bell nipple 106 with a “Rotating Control Device” (RCD) 601 in order to exchange the conventional open-loop system, which is open to atmosphere, with a closed loop system, which can be pressurized. The closed loop system can direct fluid through an MPD system 602 containing a “Pressure Control Device” (PCD) 603 that can manipulate the pressure at the surface 206 of the annulus to control the wellbore pressure in the annulus 204.

FIG. 7 is an illustrative chart of wellbore pressure while employing Managed Pressure Drilling techniques in order to operate within the bounds of a narrow drilling window in accordance with FIG. 5. FIG. 7 illustrates MPD ECD 402 and MPD EMW 403 successfully within a narrow drilling window 303 by employing MPD techniques. Because MPD techniques enable the possibility of maintaining wellbore pressure within the narrow drilling window 303, MPD is therefore especially useful in scenarios where the mud weight can be lowered such that the MPD ECD 402 is within the narrow drilling window 303 while the pressure created by an MPD system 602 can be applied to the annulus 204, shown in FIG. 2, to replace the drop in friction pressure when circulating has ceased in order to maintain the desired annular pressure profile. MPD can also be useful in several other applications including but not limited to avoiding pressure-related “Non-Productive Time” (NPT) events such as stuck pipe, hole collapse, connection gas, lost circulation, and improving the ability to characterize formations, drill wells faster, and increase post-drilling well production.

The effectiveness of MPD is significantly coupled with its ability to control the pressure at the surface 206 of the annulus. However, the ability of the MPD system 602 to accurately control the pressure at the surface 206 of the annulus can be hindered in various ways, including but not limited to an inefficient control system architecture, ineffective software, misappropriated pressure sensors, and necessary human operation. One cohesive example is that MPD systems 602 of FIG. 6 are generally not integrated into the drilling rig 101 of FIG. 1. The result is manual control of the mud pumps 104 by a human operator. The objective of the connection process while employing MPD is to increase the pressure at the surface 206 of the annulus with the MPD system 602 while the mud pumps 104 decrease their flow rate such that the bottomhole pressure (BHP) 404 is approximately equal to the MPD ECD 402 until the mud pumps 104 have completely ceased operation and the PCD 603 is completely shut, maintaining the pressure at the surface of the annulus 206 and thus inside the annulus 204 such that the MPD EMW 403 while circulation has ceased is also equal to the BHP 404, which has remained constant throughout the process. However, the staggered operation of the mud pumps and therefore flow rate creates difficulty for even an automated MPD system 602 to effectively control the measured pressure to its desired pressure setpoint during the connection process, resulting in inaccuracy that can typically fluctuate well over +/−100% of the desired pressure at the surface of the annulus 206. Another common example is the inability to control the pressure within any desirable tolerance of the pressure setpoint, even using an MPD system during the connection process, which may be a result of several inadequacies including but not limited to an inefficient control system architecture, ineffective software, misappropriated pressure sensors, not having the ability to monitor flow rate, and necessary human operation of the mud pumps 104 or MPD system 602.

FIG. 8 is an illustrative chart showing pressures of a known drilling process using conventional Managed Pressure Drilling techniques. The light line is MPD pressure from 0 to 1000 psi starting on the left. The dark line is mud pump flow rate from 0 to 400 gallons per minute (gpm) starting on the left. The vertical column is time starting at the top. A common ad-hoc attempt to solve the above described challenges is illustrated in FIG. 8, which demonstrates common performance of a typical MPD system 602 of FIG. 6. The flow rate 801 was manually decreased by a human operator to a marginal output 802 so that the MPD pressure 803 could be slowly controlled during its transitory process. However, as illustrated in label 804, this process results in the wellbore pressure decreasing then being increased rather than being maintained constant throughout the connection process, defeating the purpose of implementing MPD in the first place. A lack of pressure replacement while decreasing mud circulation mud in the annulus, results in a decrease in wellbore pressure before the MPD system can apply pressure at the surface 206 of the annulus. The consequences of either of the aforementioned cases are nonexclusive examples of deficiencies that may cause many undesired operational scenarios, which can subsequently result in millions of dollars in production losses, equipment damage, and other losses.

Therefore, there remains a need for an improved method and system of Managed Pressure Drilling that accommodates inaccuracy of pressure management and human operation of control systems.

BRIEF SUMMARY OF THE INVENTION

The present disclosure provides a managed pressure drilling method and system that accommodates timely and accurate control of surface pressure in order to maintain appropriate wellbore pressure of a well. The system and method can use a minimal set of inputs, such as a measured pressure input, with a control software hierarchy described herein to improve the accuracy of the controlled pressure and automation of drilling rig components over conventional Managed Pressure Drilling (MPD) systems. Because the method compensates for the real pressure rate of change using the pressure input, the method and system allow the implementation of MPD techniques in legacy applications and drilling rigs. The system and method can reduce human error and inefficiencies that directly degrade the quality of MPD techniques and improve wellbore drilling and hydrocarbon production performance within the industry.

The disclosure provides a method for controlling operations of a drilling rig through a system, the method comprising: acquiring a measured pressure within fluid lines in communication with a wellbore in real time; calculating a first magnitude of error between the measured pressure and a target pressure; calculating an output value proportional to the first magnitude of error between the measured pressure and the target pressure, the output value being a pressure rate of change target; calculating a second magnitude of error between the pressure rate of change target and a pressure rate of change, the pressure rate of change being a difference in the acquired measured pressure and an average of a plurality of prior measured pressures, the difference being divided by an amount of time between the acquired measured pressure and a prior measured pressure; calculating a second output value that is a sum of a proportional magnitude of real time error between the pressure rate of change target and the pressure rate of change and a proportional sum of a plurality of prior errors between the pressure rate of change target and the pressure rate of change, the second output value being a position setpoint; using the second output value to generate a process signal; using the process signal to actuate a pressure control device; and iterating the process to regulate a pressure within a fluid line in communication with a wellbore.

The disclosure also provides a system to regulate a pressure within a fluid line in communication with a wellbore, comprising: a sensor configured to sense a pressure within fluid lines in communication with a wellbore; a controller configured to calculate a first magnitude of error between the measured pressure and a target pressure, calculate an output value proportional to the first magnitude of error between the measured pressure and the target pressure, the output value being a pressure rate of change target, calculate a second magnitude of error between the pressure rate of change target and a pressure rate of change, the pressure rate of change being a difference in the acquired measured pressure and an average of a plurality of prior measured pressures, the difference being divided by an amount of time between the acquired measured pressure and a prior measured pressure, calculate a second output value that is a sum of a proportional magnitude of real time error between the pressure rate of change target and the pressure rate of change and a proportional sum of a plurality of prior errors between the pressure rate of change target and the pressure rate of change, the second output value being a position setpoint, use the second output value to generate a process signal, use the process signal to actuate a pressure control device, and iterate the process to regulate a pressure within a fluid line in communication with a wellbore.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee.

FIG. 1 is an illustrative system with surface components for drilling a subterranean borehole.

FIG. 2 is an illustrative diagram of a typical hydrocarbon well and subterranean components for drilling a borehole in accordance with FIG. 1.

FIG. 3 is an illustrative typical chart of a typical drilling window for a hydrocarbon well and salient subterranean pressures.

FIG. 4 is an illustrative typical chart of wellbore pressures conventionally operating within a drilling window in accordance with FIG. 3 and principles disclosed herein.

FIG. 5 is an illustrative typical chart of wellbore pressure conventionally operating outside the bounds of a narrow drilling window in accordance with principles disclosed herein.

FIG. 6 is an illustrative typical Managed Pressure Drilling system with surface components for conducting operations of drilling a subterranean borehole.

FIG. 7 is an illustrative chart of wellbore pressure while employing Managed Pressure Drilling techniques in order to operate within the bounds of a narrow drilling window in accordance with FIG. 5.

FIG. 8 is an illustrative chart showing pressures of a known drilling process using conventional Managed Pressure Drilling techniques.

FIG. 9 is an embodiment of surface components in a system downstream of a borehole for conducting operations of drilling a subterranean borehole according to the invention.

FIG. 10 is an embodiment of a Managed Pressure Drilling manifold and its salient components configured to work with the system of FIG. 9.

FIG. 11A is an embodiment of a control system with a plurality of control subsystems configured to work with the system of FIG. 9.

FIG. 11B is an embodiment of a control system with a plurality of control subsystems configured to work with the system of FIG. 9.

FIG. 11C is an embodiment of a control system with a plurality of control subsystems 20) configured to work with the system of FIG. 9.

FIG. 11D is an embodiment of a control system with a plurality of control subsystems configured to work with the system of FIG. 9.

FIG. 11E is an embodiment of a control system with a plurality of control subsystems configured to work with the system of FIG. 9.

FIG. 12 is an embodiment of a control system configured to work with the systems of FIG. 11A, FIG. 11B, FIG. 11C, FIG. 11D, and FIG. 11E.

FIG. 13 is an embodiment of a drilling process while employing Managed Pressure Drilling techniques according to the invention.

DETAILED DESCRIPTION

The Figures described above, and the written description of specific structures and functions below are not presented to limit the scope of what Applicant has invented or the scope of the appended claims. Rather, the Figures and written description are provided to teach any person skilled in the art how to make and use the inventions for which patent protection is sought. Those skilled in the art will appreciate that not all features of a commercial embodiment of the inventions are described or shown for the sake of clarity and understanding. Persons of skill in this art will also appreciate that the development of an actual commercial embodiment incorporating aspects of the present disclosure will require numerous implementation-specific decisions to achieve the developer's ultimate goal for the commercial embodiment. Such implementation-specific decisions may include, and likely are not limited to, compliance with system-related, business-related, government-related, and other constraints, which may vary by specific implementation, location, or with time. While a developer's efforts might be complex and time-consuming in an absolute sense, such efforts would be, nevertheless, a routine undertaking for those of ordinary skill in this art having benefit of this disclosure. It must be understood that the inventions disclosed and taught herein are susceptible to numerous and various modifications and alternative forms. The use of a singular term, such as, but not limited to, “a,” is not intended as limiting of the number of items. Further, the various methods and embodiments of the system can be included in combination with each other to produce variations of the disclosed methods and embodiments. Discussion of singular elements can include plural elements and vice-versa. References to at least one item may include one or more items. Also, various aspects of the embodiments could be used in conjunction with each other to accomplish the understood goals of the disclosure. Unless the context requires otherwise, the term “comprise” or variations such as “comprises” or “comprising,” should be understood to imply the inclusion of at least the stated element or step or group of elements or steps or equivalents thereof, and not the exclusion of a greater numerical quantity or any other element or step or group of elements or steps or equivalents thereof. The device or system may be used in a number of directions and orientations. The terms “top”, “up”, “upward”, “bottom”, “down”, “downwardly”, and like directional terms are used to indicate the direction relative to the figures and their illustrated orientation and are not absolute relative to a fixed datum such as the earth in commercial use. The term “inner,” “inward,” “internal” or like terms refers to a direction facing toward a center portion of an assembly or component, such as longitudinal centerline of the assembly or component, and the term “outer,” “outward,” “external” or like terms refers to a direction facing away from the center portion of an assembly or component. The term “coupled,” “coupling,” “coupler,” and like terms are used broadly herein and may include any method or device for securing, binding, bonding, fastening, attaching, joining, inserting therein, forming thereon or therein, communicating, or otherwise associating, for example, mechanically, magnetically, electrically, chemically, operably, directly or indirectly with intermediate elements, one or more pieces of members together and may further include without limitation integrally forming one functional member with another in a unitary fashion. The coupling may occur in any direction, including rotationally. The order of steps can occur in a variety of sequences unless otherwise specifically limited. The various steps described herein can be combined with other steps, interlineated with the stated steps, and/or split into multiple steps. Similarly, elements have been described functionally and can be embodied as separate components or can be combined into components having multiple functions. Some elements are nominated by a device name for simplicity and would be understood to include a system of related components that are known to those with ordinary skill in the art and may not be specifically described. Various examples are provided in the description and figures that perform various functions and are non-limiting in shape, size, description, but serve as illustrative structures that can be varied as would be known to one with ordinary skill in the art given the teachings contained herein. As such, the use of the term “exemplary” is the adjective form of the noun “example” and likewise refers to an illustrative structure, and not necessarily a preferred embodiment. Element numbers with suffix letters, such as “A”, “B”, and so forth, are to designate different elements within a group of like elements having a similar structure or function, and corresponding element numbers without the letters are to generally refer to one or more of the like elements. Any element numbers in the claims that correspond to elements disclosed in the application are illustrative and not exclusive, as several embodiments are disclosed that use various element numbers for like elements.

The present disclosure provides a managed pressure drilling method and system that accommodates timely and accurate control of surface pressure in order to maintain appropriate wellbore pressure of a well. The system and method can use a minimal set of inputs, such as a measured pressure input, with a control software hierarchy described herein to improve the accuracy of the controlled pressure and automation of drilling rig components over conventional Managed Pressure Drilling (MPD) systems. Because the method compensates for the real pressure rate of change using the pressure input, the method and system allow the implementation of MPD techniques in legacy applications and drilling rigs. The system and method can reduce human error and inefficiencies that directly degrade the quality of MPD techniques and improve wellbore drilling and hydrocarbon production performance within the industry.

FIG. 9 is a schematic embodiment of conventional downstream surface components that can be associated with drilling operations as well as Managed Pressure Drilling system components according to the invention. FIG. 10 is an embodiment of a Managed Pressure Drilling manifold and its salient components configured to work with the system of FIG. 9. Drilling fluid, rock cuttings, produced fluids, and other miscellany associated with drilling subterranean boreholes, known as well returns, are circulated through a (“Blow Out Preventer”) (BOP) stack 901 and into the RCD 902. In at least one embodiment, well returns can then either be directed to the flow line 903 by opening flow line valve 904 and closing MPD valve 905 or directed to an MPD manifold 906 by opening MPD valve 905 and closing flow line valve 904. The flow line valve 904 and MPD valve 905 may be pneumatically actuated, hydraulically actuated, electrically actuated, manually actuated, or any combination thereof. The conduit 907 for well returns to be transported to the MPD Manifold 906 can be hard piping, a hose, or any combination thereof. The conduit 907 may be coupled to the valve 905 by means of a coupler with identical or differing connections, generally referred to as a crossover, which may host a plurality of connection types such as but not limited to hammer unions and flanges. In at least one embodiment, the flow line 903 may be coupled to the valve 904 by a type of coupler (not illustrated).

The MPD manifold 906 may include a plurality of flow paths, valves, pressure control devices, sensors, and actuators. In at least one embodiment, flow paths can include but are not limited to one or another series of lines through a plurality of pressure control devices, valves, sensors, and actuators, or through a solitary line absent of any devices or obstructions. In at least one embodiment, the valves can include but are not limited to gate valves, plug valves, ball valves, globe valves, needle valves, check valves, pressure relief valves, butterfly valves, diaphragm valves, pinch valves, or any combination thereof. In at least one embodiment, the sensors can include but are not limited to pressure sensors, flow rate sensors, densitometers, viscometers, potentiometers, sonar sensors, torque sensors, orifice deflection sensors, electrical current sensors, or any combination thereof. In at least one embodiment, the pressure control devices can include but are not limited to chokes, wedge valves, orifice plates, throttle valves, globe valves, ball valves, or any combination thereof. In at least one embodiment, the actuators can be but are not limited to electric, hydraulic, pneumatic, manual actuators, or any combination that can include but are not limited to worm gear configurations, linear configurations, or any combination thereof.

In this embodiment, the MPD manifold 906 includes a single flow path for well returns through an upstream valve 1001, upstream of at least one sensor and for redundancy advantageously two sensors 1002 and 1003 which can be pressure sensors, installed in flange adapter 1004, which is upstream of a pressure control device 1005, which is upstream of a downstream valve 1006, which is upstream of a conduit 908 that transports well returns to the flow line 903. The MPD manifold 906 can be located on the drilling rig floor, which allows for faster rig relocations between wells on a single pad, saving significant amounts of time as compared to the obligation of disconnecting, moving, and reconnecting MPD equipment each time the drilling rig relocation to another well. The MPD manifold 906 being located on the drilling rig floor also allows for convenient access for valve alignments and pressure control device repair and maintenance, which eliminates the risk-laden process of working at heights in a man-lift to achieve the same objectives. Additionally, the MPD manifold 906 being located on the drilling rig floor removes the need for additional pressure control devices and other equipment to be connected directly to the RCD such that the weight of that equipment poses a risk of BOP stack handling when the equipment needs to be moved, installed, or uninstalled.

In this embodiment, a valve 1001 couples the flow conduit 907 and flange adapter 1004. The flange adapter 1004 can have a plurality of threaded ports including but not limited to National Pipe Taper (NPT) threads, National Pipe Taper Fuel (NPTF) threads, Autoclave threads, British Standard Pipe (BSP) threads, British Standard Pipe Parallel (BSPP) threads, British Standard Pipe Taper (BSPT) threads, Society of Automotive Engineers (SAE) threads, Joint Industry Council (JIC) threads, or any combination thereof. The flange adapter 1004 can include a plurality of sensors 1002 and 1003, which at least for illustration purposes herein can be pressure sensors. The flange adapter 1004 couples the valve 1001 with the pressure control device (PCD) 1005. The PCD 1005 can include a plurality of pressure control methods and devices. In this embodiment, the PCD 1005 can include an actuator 1007, potentiometer 1008, nose cone 1009, operating stem 1010, gate 1011, seat 1012, and wear sleeve 1013. The actuator 1007 can include but is not limited to a plurality of motors, gears, circuits, circuit boards, and processors or any combination thereof configured to actuate the PCD, sense parameters including but not limited to PCD position, electrical current, torque, or any combination thereof, and convey the sensed parameters to a control system. The potentiometer 1008 can include instrumentation configured to measure an electromotive force by balancing it against the potential difference produced by passing a known current through a known variable resistance in order to sense the partial open or closed position of the PCD. The operating stem 1010 can be threaded inside of a gate 1011 and configured to translate the gate 1011 along a longitudinal axis of the PCD 1005. The gate 1011 can restrict, allow, or disallow well returns flowing into the PCD 1005 and striking the nose cone 1009, which can be configured to withstand the impact force created by the pressurized well returns at varying velocities, to flow along the longitudinal axis of the PCD 1005 by traveling along the operating stem 1011 and creating a partial or complete pressure-capable seal with seat 1012. If only restricting the flow of well returns, the well returns will circulate through the seat 1012 and wear sleeve 1013, which can be configured to withstand erosion in order to protect the body of the PCD 1005. In this embodiment, the MPD manifold 906 can also have a block 1014, which can be configured to couple the PCD 1005 with a flange adapter 1015. The flange adapter 1015 can be configured to have a plurality of threaded ports not unlike flange adapter 205 and couple the block 1014 with a valve 1006. The manifold 906 can be mounted onto a frame 1018 and also include a lifting device 1016, operated by hand at a device 1017, such as a hand wheel.

FIG. 11A, FIG. 11B, FIG. 11C, FIG. 11D, and FIG. 11E are embodiments of a control system 1108 with a plurality of control subsystems configured to work with the system of FIG. 9. In these illustrative embodiments, the subsystem 1101 can include a plurality of devices including but not limited to Programmable Logic Devices (PLC), Variable Frequency Drives (VFD), power transformers, circuit breakers, and barrier cards. The subsystem 1101 can be configured to monitor and control the devices within the MPD manifold 906, which may include but is not limited to sensing pressure within one or more lines of the MPD manifold 906, one or more parameters sensed by the actuator 1007, one or more parameters sensed by the potentiometer 1008, one or more other physical parameters within the fluid lines of the manifold 906 such as but not limited to fluid density, fluid viscosity, flow rate, or any combination thereof. The subsystem 1102 can include a plurality of devices including but not limited to Programmable Logic Devices (PLC), Variable Frequency Drives (VFD), power transformers, circuit breakers, and barrier cards. The subsystem 1101 and the subsystem 1102 can also be configured to perform a plurality of calculations involving the aforementioned sensed parameters along with inputs created by a human, known as the “user,” store these inputs and calculations, and convey data and process signals to a plurality of other control systems and devices. The subsystem 1102 can be configured to monitor a plurality of parameters amongst a plurality of devices and control such plurality of devices throughout the drilling rig. These devices can include but are not limited to the mud pumps, MPD system, top drive, drawworks, BOP stack devices, and other conventional drilling rig devices in any combination thereof.

FIG. 11A is an embodiment of a control system with a plurality of control subsystems configured to work with the system of FIG. 9. In FIG. 11A, the subsystem 1101 and subsystem 1102 can send and receive data to each other via a gateway 1104 and a plurality of network cables and devices. In this embodiment, the subsystem 1101 can record the pressure within the manifold 906 upstream of the PCD 1005 sensed by the sensors 1002 and 1003 into a database and performing calculations with that data. Human Machine Interface (HMI) 1103 can be configured to be an interface from which a user can monitor a plurality of parameters from a plurality of devices and control such devices of subsystem 1101 and subsystem 1102.

FIG. 11B is an embodiment of a control system with a plurality of control subsystems configured to work with the system of FIG. 9. FIG. 11B is an embodiment similar to FIG. 11A with the exception that the subsystem 1101 can contain gateway 1104 such that the system installation and communication capabilities can be improved via a plurality of methods including but not limited to software integration and data latency decreases.

FIG. 11C is an embodiment of a control system with a plurality of control subsystems configured to work with the system of FIG. 9. FIG. 11C is an embodiment similar to FIG. 11A with the exception that MPD HMI 1105 can be configured to be an interface from which a user can monitor a plurality of parameters from a plurality of devices and control such devices of subsystem 1101 while Rig HMI 1106 can be configured to be an interface from which a user can monitor a plurality of parameters from a plurality of devices and control such devices of subsystem 1102. This embodiment demonstrates the ability to perform the method and system according to the invention where the integration of the software of subsystem 1101 and the software of subsystem 1102 can be intentionally regulated with a gateway 1104, which increases the range of compatible drilling rigs on which to implement the invention.

FIG. 11D is an embodiment of a control system with a plurality of control subsystems configured to work with the system of FIG. 9. FIG. 11D is an embodiment similar to FIG. 11C with the exception that the process data can only be sent by subsystem 1102 to and received by subsystem 1101 via gateway 1104. This embodiment demonstrates the ability to perform the method and system according to the invention where the software of subsystem 1101 and the software of subsystem 1102 can be completely separate, which increases the range of compatible drilling rigs on which to implement the invention

FIG. 11E is an embodiment of a control system with a plurality of control subsystems configured to work with the system of FIG. 9. FIG. 11E is an embodiment similar to FIG. 11A with the exception that subsystem 1107 contains both subsystem 1101 and subsystem 1102. This embodiment demonstrates the ability to eliminate gateway 1104 and ancillary HMIs such that HMI 1103 can monitor a plurality of parameters from a plurality of devices and control such devices of subsystem 1107.

FIG. 12 is an embodiment of a controller configured to work with the systems of FIG. 11A, FIG. 11B, FIG. 11C, FIG. 11D, and FIG. 11E. In an embodiment, the measured parameter can be a pressure, flow rate, density, viscosity, electrical current, torque, position, or any combination thereof. For illustration and without limitation, the parameter can be pressure and can be used as an example in the remaining description. In an embodiment, input 2 1203 can be a target of measured pressure 1202, which can include but is not limited to the aforementioned examples. In an embodiment, output 1 1204 can be but is not limited to a target derivative pressure. In an embodiment, input 3 1205 can be but is not limited to an acquired derivative of pressure. In an embodiment, output 2 1206 can be but is not limited to a position setpoint. In this embodiment, the controller 1201 can acquire and record a measured pressure 1202 within the lines of manifold 906 in real time via sensors 1002 and 1003. The controller 1201 can be configured to calculate the magnitude of error between the measured pressure 1202 and a target pressure 1203, which is input from a user, and calculate an output value 1204, which is the pressure rate of change target. The pressure rate of change target 1204 can be proportional to the magnitude of error between the measured pressure 1202 and the target pressure 1203. The controller 1201 can also be configured to calculate the magnitude of error between the pressure rate of change target 1204 and a pressure rate of change 1205, the pressure rate of change 1205 being a difference in the acquired measured pressure and an average of a plurality of prior measured pressures, the difference being divided by an amount of time between the acquired measured pressure and a prior measured pressure, and calculating a second output value 1206, which is a position setpoint. The position setpoint 1206 is a sum of a proportional magnitude of real time error between the pressure rate of change target and the pressure rate of change and a proportional sum of a plurality of prior errors between the pressure rate of change target and the pressure rate of change. The controller 1201 can further be configured to use the second output value for position setpoint 1206 to generate a process signal and send such process signal to actuator 1007, which actuates PCD 1005 by translating gate 1011 along its longitudinal axis in order to adjust flow of well returns, thereby manipulating pressure upstream of PCD 1005 inside the MPD manifold 906. The process is then iterated until the measured pressure 1202 is within a defined tolerance of the target pressure 1203.

The controller 1201 can also be configured to precisely determine the open/close position of the PCD 1005, more specifically the current extended position of gate 1011, in all positions along its longitudinal axis. One method for accomplishing this precision can be via controller 1201 performing a calibration algorithm. The calibration algorithm can be an automated software process performed by controller 1201 that utilizes feedback from the actuator 1007 that can be but is not limited to torque and motor speed. In an embodiment, the torque and speed feedback can be provided by an absolute motor shaft encoder or an incremental motor shaft encoder within actuator 1007. To determine the fully open position of PCD 1005, a positive static speed may be commanded and monitored by the controller 1201 while a torque feedback from actuator 1007 is also monitored by controller 1021. In an embodiment, controller 1201 commands the motor speed of the actuator 1007 to reduce until reaching zero speed in an inverse proportional manner to an increase in torque feedback. After the motor speed reaches zero speed, the absolute position of the PCD 1005 is saved inside the 20) PLC of subsystem 1101. To determine the fully closed position of PCD 1005, a negative static speed may be commanded and monitored by the controller 1201 while a torque feedback from actuator 1007 is also monitored by controller 1021. In an embodiment, controller 1201 commands the motor speed of the actuator 1007 to reduce until reaching zero speed in a directly proportional manner to a decrease in torque feedback. After the motor speed reaches zero speed, the absolute position of the PCD 1005 is saved inside the PLC of subsystem 1101. Using the difference in countable absolute positions between the open and closed calibration positions and then dividing by 100%, a percentage-based position control and feedback framework can be created within subsystem 1101 and controller 1201.

The subsystem 1101 can also be configured to use sensor 1002 and sensor 1003 in a manner such that a more accurate pressure feedback can be obtained by interpreting the measured pressure from both sensor 1002 and sensor 1003 simultaneously. A plurality of pressure sensor feedbacks can be calculated within subsystem 1101 and controller 1201 as well as the ability to select which pressure feedback to utilize for further calculations. Within the controller 1201, electronic instructions for determining which of a plurality of pressure feedbacks to utilize can exist. This section process can be determined but is not limited to pressor sensor feedback range errors, pressure sensor failure mechanisms, pressure sensor feedback mismatches, or any combination thereof.

FIG. 13 is an embodiment of a drilling process while employing Managed Pressure Drilling techniques according to the invention. More specifically, FIG. 13 is an embodiment of an MPD connection process according to the invention. Referring in part to FIGS. 1-3, a typical MPD connection process can be simplified into three main phases: the mud pumps 104 ramping down, the PCD 1005 trapping the desired target pressure 1203, and the mud pumps 104 ramping up after a new stand of drill pipe has been added to the drill string 102. In an embodiment, flow rate 1301 can be ramped down via a controlled speed gradient according to the invention. This controlled speed gradient ramp of the flow rate 1301 is important to achieving results demonstrated in FIG. 13. A user can input values for the ramp such as but not limited to mud pumps 104 ramp time, mud pump 109 ramp target speed, mud pump 110 ramp target speed, and mud pump 111 ramp target speed via an HMI such as but not limited to HMI 1103. Via HMI 1103, another input can be available to activate the ramp sequence. Valid values for mud pump ramp target speeds can be values greater than a same mud pump's current speed, or less than the same mud pump's current speed, but greater than or equal to zero speed. Upon activation of the mud pump ramp down active input, the MPD subsystem 1101 can determine the necessary values that are sent to the subsystem 1102 in order to control the speeds of mud pump 109, mud pump 110, and mud pump 111, such that the speeds are controllably ramped from each of the currently operating mud pumps speed to the mud pump target speeds entered by a user from the HMI 1103 input field over the time frame entered into the mud pump ramp target speed. This controlled ramping of the mud pumps allows the controller 1201 to produce faster and more accurate position setpoint 1206 commands than compared to a typical MPD 25 system. As the mud pumps 104 ramp down, the flow rate 1301 decreases in a controlled fashion. Simultaneously, the subsystem 1101 can create new target pressures 1203, illustrated by line 1303, based on the flow rate 1301 and send those target pressures 1203 to controller 1201. By way of the invention, outputs of position setpoint 1206 then increase/decrease, illustrated by the position feedback 1302, to control the measured pressure 1202, illustrated by line 1304, in such a way to minimize error between the measured pressure 1202 and target pressure 1203. This cohesive, integrated process across multiple systems achieves MPD connections with accuracy superior to typical MPD systems.

Part of the above cohesive process can be the accurate detection of the current flow rate 1301. One method for determining accurate flow rate 1301 can be using a combination of data from subsystem 1102 and subsystem 1101. Positive displacement mud pumps 104 provide volumetric flow rate that is directly proportional to its crankshaft speed and motor speed via a gear box with a known ratio and a belt with a known ratio that couples the motor shaft to the crankshaft, which operates the displacement pistons. In addition to the mud pump motor speed, other factors that can be used to determine accurate flow rate from each of the mud pumps 104 individually are but not limited to mud pump liner size, mud pump stroke length, gear box and belt ratio, number of displacement pistons, pump efficiency, current measured flow rate, flow rate setpoint, or any combination thereof. In one embodiment according to the invention, each of the values needed to calculate each of the mud pumps 104 flow rate can be available to the subsystem 1101. Values such as individual mud pumps 104 liner size and motor speed can be available in subsystem 1102, which can be sent to subsystem 1101 via gateway 1104. Additionally, values such as mud pump stroke length and gear box and belt ratio can be available to subsystem 1101 via HMI 1103 via gateway 1104. When the aforementioned values are combined arithmetically, the flow rate of each of the mud pumps 104 can be calculated. By summing the flow rate of each of the mud pumps 104, the total flow rate 1301 can be surmised.

Once the ramp 1305 has been completed and the mud pumps 104 have ceased operation such that flow rate 1301 is zero, the PCD 1005 has trapped the measured pressure 1304 according to the target pressure 1303. Over the course of the length of time 1306, new drill pipe is being added to the drill string 102. Once new drill pipe has been added to the drill string 102, the phase 1307 can commence. During phase 1307, the mud pumps 104 are started such that flow rate 1301 begins to rise back to the desired nominal drilling flow rate. As the flow rate 1301 increases, the target pressure 1303 decreases, which causes the controller 1201 via its iterative process to begin increasing the position setpoint 1206, which lowers the measured pressure 1304 in accordance with minimizing the error between measured pressure 1304 and target pressure 1303. In an embodiment according to the invention, the mud pumps 104 can be turned on immediately without a ramp in contrast to ramp 1305, made possible by the accurate flow rate 1301 detection via the aforementioned parameters and algorithms coordinating the processes of subsystem 1101 and 1102 together such that future flow rate of 1301 can be predicted by subsystem 1102 and utilized by subsystem 1101 to use controller 1201 in a proactive way that actuates PCD 1005 based on expected future measured pressure 1202. This maintains the improved accuracy as compared to typical MPD systems while also increasing the speed and efficiency by which the connection process is made, potentially saving tens to hundreds of hours per well, which is typically equivalent to hundreds of thousands of dollars.

Subsystem 1101 and subsystem 1102 can also be configured to improve MPD system operative robustness via safety redundancies with drilling rig 101 components and devices such as but not limited to an emergency mud pumps 104 shut off command (E-stop). This command can be sent via a communication link between the subsystem 1101 and subsystem 1102. This communication link can be facilitated via gateway 1104. The E-stop capability can be critical in protecting the integrity of the wellbore, rig equipment, and the safety of personnel at and around the drilling rig 101 site. In an embodiment, this E-stop functionality can by monitoring the subsystem 1101 control mode and monitoring the status and speed of each of the mud pumps 104 using the communication link to subsystem 1102 according to the invention. The E-stop command can be sent by subsystem 1101 to subsystem 1102 in order to execute the process.

Subsystem 1101 and subsystem 1102 can also be configured to protect the integrity of communications between each system via a bidirectional communication fault tolerance detection between subsystem 1101 and subsystem 1102. This bidirectional communication fault tolerance detection can reduce or prevent a plurality of undesirable conditions including but not limited to wellbore damage, equipment damage, and others. In an embodiment, one method for detection of a communication link failure can be to create a value in a memory location in subsystem 1102 that increments the value via a known cycle time. According to the invention, this value is sent from subsystem 1102 to subsystem 1101, for example via gateway 1104, where subsystem 1101 will monitor the incrementing value at the aforementioned cycle time. This value can then be returned to subsystem 1102 where it will be monitored by subsystem 1102 to ensure the value has updated within the known cycle time. In an embodiment, subsystem 1101 can be put into a safe operable mode in the event that the value does not update at the known cycle time, mitigating the risk of the aforementioned undesirable conditions. In addition, subsystem 1101 and subsystem 1102 can generate an alert that can be monitored by a user at HMI 1103 to indicate the status of the bidirectional communication fault tolerance detection.

Subsystem 1101 can also be configured to automatically change operable modes based on a plurality of feedbacks and settings within subsystem 1101 and subsystem 1102, including but not limited to communication failure, bypassing pressure thresholds, power failure, or any combination thereof. In an embodiment, if a measured pressure 1202 is detected in excess of a first high pressure threshold, subsystem 1101 may change operable modes. These operable modes can include but are not limited to manual position control of the PCD 1005 mode, a user-input target pressure 1203 control mode, an automatic target pressure 1203 control mode, or any combination thereof. In addition, the subsystem 1101 may create a new target pressure 1203 command for controller 1201 such as, for example, 90% of the first pressure threshold. In another embodiment, if a measured pressure 1202 is detected in excess of a second high pressure threshold, the subsystem 1101 may command, for example, controller 1201 to command a full-open position setpoint 1206 of the PCD 1005 in order to mitigate the risk of an undesirable condition such as but not limited to line plugging, PCD 1005 erosion, mud pumps 104 deadheading, or any combination thereof.

Other and further embodiments utilizing one or more aspects of the inventions described above can be devised without departing from the disclosed invention as defined in the claims. For example, method and system of pressure control can be performed and installed in different locations throughout the drilling rig that may result in a functionally synonymous result. These variations are considered typical MPD techniques for purposes herein. Other variations are limited only by the scope of the claims.

The invention has been described in the context of preferred and other embodiments, and not every embodiment of the invention has been described. Obvious modifications and alterations to the described embodiments are available to those of ordinary skill in the art. The disclosed and undisclosed embodiments are not intended to limit or restrict the scope or applicability of the invention conceived of by the Applicant, but rather, in conformity with the patent laws, Applicant intends to protect fully all such modifications and improvements that come within the scope of the following claims.

Claims

1. A method for controlling operations of a drilling rig through a system, the method comprising:

acquiring a measured pressure within fluid lines in communication with a wellbore in real time; and

calculating a first magnitude of error between the measured pressure and a target pressure; and

calculating an output value proportional to the first magnitude of error between the measured pressure and the target pressure, the output value being a pressure rate of change target; and

calculating a second magnitude of error between the pressure rate of change target and a pressure rate of change, the pressure rate of change being a difference in the acquired measured pressure and an average of a plurality of prior measured pressures, the difference being divided by an amount of time between the acquired measured pressure and a prior measured pressure; and

calculating a second output value that is a sum of a proportional magnitude of real time error between the pressure rate of change target and the pressure rate of change and a proportional sum of a plurality of prior errors between the pressure rate of change target and the pressure rate of change, the second output value being a position setpoint; and

using the second output value to generate a process signal; and

using the process signal to actuate a pressure control device; and

iterating the process to regulate a pressure within a fluid line in communication with a wellbore.

2. The method of claim 1, further comprising controlling the pressure control device of the drilling rig with one or more subsystems of the system.

3. The method of claim 1, further comprising controlling one or more mud pumps of the drilling rig with a first subsystem of the system.

4. The method of claim 3, further comprising controlling a pressure control device of the drilling rig with a second subsystem of the system.

5. The method of claim 4, further comprising sending a signal from the second subsystem to the first subsystem to control operation of the mud pumps.

6. The method of claim 5, further comprising automatically generating the signal based on a state of the mud pumps and a state of the pressure control device.

7. The method of claim 5, further comprising controlling the first subsystem and the second subsystem from one human machine interface.

8. The method of claim 5, further comprising controlling the first subsystem and the second subsystem from separate human machine interfaces.

9. The method of claim 1, wherein calculating the first magnitude of error between the measured pressure and the target pressure comprises generating a target pressure based on at least one of a target flow rate and a flow rate feedback.

10. The method of claim 9, further comprising generating at least one of the target flow rate and the flow rate feedback based on an RPM feedback of a variable frequency drive of one or more mud pumps of the drilling rig.

11. The method of claim 3, further comprising automatically manipulating control of the one or more mud pumps based on calculating a target flow rate, a flow rate feedback, and a target derivative of flow rate.

12. The method of claim 4, further comprising utilizing a bidirectional communication fault tolerance detection between the first subsystem and the second subsystem.

13. The method of claim 1, further comprising automatically configuring position limits of the pressure control device and controlling the pressure control device within the limits, inclusive.

14. The method of claim 13, further comprising verifying a position of a pressure control device via a potentiometer.

15. The method of claim 1, further actuating the pressure control device via a programmed routine when the measured pressure exceeds a pressure threshold.

16. A system to regulate a pressure within a fluid line in communication with a wellbore, comprising:

a sensor configured to sense a pressure within fluid lines in communication with a wellbore;

a controller configured to calculate a first magnitude of error between the measured pressure and a target pressure, calculate an output value proportional to the first magnitude of error between the measured pressure and the target pressure, the output value being a pressure rate of change target, calculate a second magnitude of error between the pressure rate of change target and a pressure rate of change, the pressure rate of change being a difference in the acquired measured pressure and an average of a plurality of prior measured pressures, the difference being divided by an amount of time between the acquired measured pressure and a prior measured pressure, calculate a second output value that is a sum of a proportional magnitude of real time error between the pressure rate of change target and the pressure rate of change and a proportional sum of a plurality of prior errors between the pressure rate of change target and the pressure rate of change, the second output value being a position setpoint, use the second output value to generate a process signal, use the process signal to actuate a pressure control device, and iterate the process to regulate a pressure within a fluid line in communication with a wellbore.

17. The system of claim 16, wherein the system further comprises a subsystem configured to control a pressure control device of a drilling rig at the wellbore.

18. The system of claim 16, wherein the system further comprises a first subsystem configured to control one or more mud pumps of a drilling rig at the wellbore.

19. The system of claim 18, wherein the system further comprises a second subsystem configured to control a pressure control device of a drilling rig at the wellbore.

20. The system of claim 19, wherein the second subsystem is configured to send a signal to the first subsystem to control operation of the mud pumps of a drilling rig.

21. The system of claim 20, wherein the signal is automatically generated based on a state of the mud pumps and a state of the pressure control device.

22. The system of claim 19, wherein control of the first subsystem and the second subsystem is executed from one human machine interface.

23. The system of claim 19, wherein control of the first subsystem and the second subsystem is from separate human machine interfaces.

24. The system of claim 16, wherein the system further comprises a subsystem configured to control the pressure control device and one or more mud pumps of the drilling rig at the wellbore.

25. The system of claim 16, wherein the target pressure is generated based on at least one of a target flow rate and a flow rate feedback.

26. The system of claim 25, wherein at least one of the target flow rate and the flow rate feedback comprises a calculation based on an RPM feedback of a variable frequency drive of at least one mud pump.

27. The system of claim 18, wherein the control of the one or more mud pumps can be manipulated automatically based on a calculation involving a target flow rate, a flow rate feedback, and a target derivative of flow rate.

28. The system of claim 19, wherein the first subsystem and the second subsystem are configured to be use a bidirectional communication fault tolerance detection.

29. The system of claim 16, wherein the system is configured to automatically configure position limits of the pressure control device and control the pressure control device within the limits, inclusive.

30. The system of claim 29, wherein the position of the pressure control device is verified via a potentiometer.

31. The system of claim 17, wherein the subsystem is configured to actuate the pressure control device via a programmed routine when the measured pressure exceeds a pressure threshold.

32. The system of claim 16, wherein the system is located on a drilling rig site.

33. The system of claim 16, wherein the system is located on a drilling rig floor of the drilling rig at the wellbore.