AUTOMATED WORKFLOWS USING TRANSIENT, MULTIPHASE ANALYSIS TO IMPROVE WELL CONTROL PLANNING FOR MANAGED PRESSURE DRILLING OPERATIONS

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to and the benefit of U.S. Provisional Patent Application Ser. No. 63/627,508 titled “AUTOMATED WORKFLOWS USING TRANSIENT, MULTIPHASE ANALYSIS TO IMPROVE WELL CONTROL PLANNING FOR MANAGED PRESSURE DRILLING OPERATIONS” filed Jan. 31, 2024, the disclosure of which is incorporated herein by reference in its entirety.

BACKGROUND OF THE DISCLOSURE

Wellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes. For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations. Wellbores used to produce or extract fluids may be formed in earthen formations using earth-boring tools such as drill bits for drilling wellbores and reamers for enlarging the diameters of wellbores.

Formation fluids may enter the wellbore during drilling operations, referred to as an “influx” of formation fluid. A managed pressure drilling (MPD) system provides a closed-loop circulation in which a bottomhole pressure is balanced and managed by controlling a choke pressure at the surface. The MPD system consist of instrumentation that may detect small influxes and rapidly control the back pressure to manage minor influxes. Larger influxes may expose wellbore equipment to excessive pressures. Thus, when influxes are encountered, a drilling operating should consider whether the influx will cause the wellbore equipment to approach its operational limits.

SUMMARY

In some aspects, the techniques described herein relate to a method of determining an influx management envelope for a wellbore extending through an earth formation. Using dynamic pressure model of a simulation cluster, for a drilling fluid density and each of a plurality of choke pressures, the dynamic pressure model generates an output including a dynamic pressure profile of an annular pressure of the drilling fluid throughout the wellbore. For each output, using a multiphase transient model of the simulation cluster, the multiphase transient model determines a post influx surface pressure for each of a plurality of influx volumes.

In some aspects, the techniques described herein relate to a method of generating an influx management envelope for a wellbore. For a first influx volume, an equation of state transient multiphase model in a simulation cluster determines transient temperatures and pressures along the wellbore and a composition of the first influx volume for each of a plurality of sets of wellbore parameters. The method includes determining a post influx surface pressure as a result of the first influx volume for each of the plurality of sets of wellbore parameters. For a second influx volume and each of the plurality of sets of wellbore parameters, the equation of state transient multiphase model in the simulation cluster determines in parallel a post influx surface pressure as a result of the second influx volume at each of the plurality of sets of wellbore parameters.

In some aspects, the techniques described herein relate to a method of generating an influx management envelope for a wellbore. A dynamic pressure model generates a dynamic pressure profile of a wellbore for a drilling fluid having a density. A transient multiphase model receives an output from the dynamic pressure model and determining a post influx surface pressure of the drilling fluid for a given influx volume. The method includes determining whether the post influx surface pressure exceeds a pressure threshold. The method further includes determining whether to change circulation of the drilling fluid, whether to change the managed pressure drilling equipment, or whether to utilize secondary well control equipment to mitigate the influx volume.

This summary is provided to introduce a selection of concepts that are further described in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. Additional features and aspects of embodiments of the disclosure will be set forth herein, and in part will be obvious from the description, or may be learned by the practice of such embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other features of the disclosure may be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 is an example of an environment in which drilling may take place, according to at least one embodiment of the present disclosure;

FIG. 2 is an example of a drilling system that may be used to drill a well, according to at least one embodiment of the present disclosure;

FIG. 3 is an example computing system that may be used in connection with the drilling system, according to at least one embodiment of the present disclosure;

FIG. 4 illustrates an example of a dynamic well control workflow, according to at least one embodiment of the disclosure;

FIG. 5 illustrates an example overview of driller's method, according to at least one embodiment of the disclosure;

FIG. 6 illustrates an example bottomhole pressure using the models described herein compared to another baseline model;

FIG. 7 illustrates an example casing shoe pressure using the models described herein compared to another baseline model;

FIG. 8 illustrates an example comparison of choke pressure curves using the models described herein compared to another baseline model using the models described herein compared to another baseline model;

FIG. 9 illustrates an example pit gain comparison using the models described herein compared to another baseline model;

FIG. 10 illustrates an example gas flowrate out using the models described herein compared to another baseline model;

FIG. 11 illustrates an example of free and dissolved gas using the models described herein compared to another baseline model;

FIG. 12 illustrates an example of how parallelization may be used to drive performance of the models described herein; and

FIG. 13 is a simplified flow diagram illustrating a method of generating an influx management envelope, according to at least one embodiment of the disclosure.

FIG. 14 is a simplified flow diagram illustrating a method of generating an influx management envelope, according to at least one embodiment of the disclosure.

FIG. 15 is a simplified flow diagram illustrating a method of generating an influx management envelope, according to at least one embodiment of the disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure relate to systems, methods, and computer-readable media for generating an influx management envelope (IME), and to related methods and systems for operating a wellbore. In particular, the present disclosure relates to the automation of the generation of the influx management envelope, elimination the manual entry of different operational parameters to generate the influx management envelope. For example, according to embodiments described herein, a system is configured to determine an influx management envelope by simultaneously determining the boundaries of the influx management envelope using a dynamic pressure model and a transient multiphase model using a simulation cluster, such as using cloud computing (e.g., a cloud-based simulation cluster).

The influx management envelope may be generated using a simulation cluster (also referred to as an “influx management envelope engine” or an “influx management envelope manager”) including a dynamic pressure model (also referred to as a “dynamic pressure engine” and a transient multiphase model (also referred to as a “transient multiphase engine”). Multiple parameters of the influx management envelope may be determined in parallel using the simulation cluster. For example, the calculations for determining the influx management envelope may be performed in parallel, substantially increasing the processing speed at which the influx management envelope is generated. Given the properties of the earth formation and the wellbore (e.g., the pore pressure, the fracture pressure, the wellbore length, the diameter of the wellbore) and the density of the drilling fluid, the dynamic pressure model generates an output including a dynamic pressure profile of a drilling fluid along the wellbore, such as in an annular space between the sidewalls of the earth formation and the drill string, which may be referred to as the annular pressure. The dynamic pressure profile of the drilling fluid may include one or both of the equivalent circulating density (ECD) and the equivalent Static Density (ESD) profile of the drilling fluid. In addition, in some embodiments, the dynamic pressure model is configured to determine a temperature profile of the temperature of the wellbore and/or the temperature of the earth formation proximate the wellbore.

The transient multiphase model may be configured to receive the output from the dynamic pressure model. The transient multiphase model may receive the output from the dynamic pressure model and generate the influx management envelope based on the output determine (e.g., estimate, calculate) at least a post influx surface pressure for each of a plurality of influx volumes (e.g., kicks). In some embodiments, the post influx surface pressure for each influx volume may be determined using the transient multiphase model to generate the influx management envelope. The transient multiphase model may iteratively generate the influx management envelope using the output received from the dynamic pressure model (for a given density of the drilling fluid which was input into the dynamic pressure model) by determining the post influx surface pressure for a plurality of different influx volumes and intensities. In some embodiments, post influx surface pressure for a plurality of different influx volumes may be determined in parallel, such as by utilizing a cloud computing simulation cluster, to increase the processing speed of the system. In addition, simultaneously to determining the pressure profile for a given drilling fluid density with the dynamic pressure model, the transient multiphase model may generate an influx management envelope for at least a drilling mud having a different density (such as a drilling mud for which the dynamic pressure profile has already been generated by the dynamic pressure model). In some embodiments, the influx management envelope (including both of the dynamic pressure model and the transient multiphase model) may generate the influx management envelope using a simulation cluster in the cloud (e.g., at a remote server).

Transient multiphase technology has proven to be more accurate and reliable for well control planning, but it has been too complex to automate and integrate into automated engineering systems. Accordingly, many influx management envelopes may be generated based on (e.g., limited to) the single bubble considerations, wherein the influx volume is treated as a single bubble of material that travels through the wellbore as a bubble. According to embodiments described herein, the influx management envelope is generated using the transient, multiphase model and based on an output from the dynamic pressure model. The use of the cloud-based simulation cluster according to embodiments of the disclosure facilitates generation of the influx management envelope using the transient multiphase model. For example, the cloud-based simulation cluster facilitates the simultaneous calculation of different variables. In addition, the cloud-based simulation cluster facilitates performing multiple iterations simultaneously to more quickly generate the influx management envelope. Thus, the transient multiphase models may be used to reduce well control risk by accurately modelling downhole variation in fluid pressure as function of operational mode, fluids, influx type, geometry, water depth and pressure and temperature conditions.

The automated workflow enables a well control engineer to run accurate multiphase simulations with the same user effort as single bubble kick tolerance tools. In special cases where more sensitivities are required, it is easy to transfer the project to the expert mode—where the automated simulation may be finetuned.

Accordingly, the methods and systems described herein improve well control planning efficiency by utilizing an automated workflow that enables integration of transient multiphase technology into modern well planning systems. The dynamic pressure model and the transient multiphase model includes relevant physical processes in the wellbore including transient temperature and acceleration (pressure waves through the wellbore). For example, the influx management envelope may be generated using a transient multiphase model having an accurate equation of state based PVT model with compositional tracking that in combination with the transient temperature and the dynamic pressure model accurately predict the transition of the wellbore fluid (e.g., the influx volume) from dissolved to free gas—a key parameter in the development of a kick.

The Driller's method has been automated with a controller network that moves the simulation through the distinct phases of the driller's circulation and may not require interaction from the user. High performance cloud computing may secure the workflow performance.

Additional details will now be provided regarding systems described herein in relation to illustrative figures portraying example implementations. For example, FIG. 1 shows one example of an environment 100 in which drilling may occur. The environment may include a reservoir 102 and various geological features, such as stratified layers. The geological aspects of the environment 100 may contain other features such as faults, basins, and others. The reservoir 102 may be located on land or offshore.

The environment 100 may be outfitted with sensors, detectors, actuators, etc. to be used in connection with the drilling process. FIG. 1 illustrates equipment 104 associated with a well 106 being constructed using downhole equipment 108. The downhole equipment 108 may be, for example, part of a bottom hole assembly (“BHA”). The BHA may be used to drill the well 106. The downhole equipment 108 may communicate information to the equipment 104 at the surface, and may receive instructions and information from the surface equipment 104 as well. The surface equipment 104 and the downhole equipment 108 may communicate using various communications techniques, such as mud-pulse telemetry, electromagnetic (EM) telemetry, or others depending on the equipment and technology in use for the drilling operation.

The surface equipment 104 may also include communications means to communicate over a network 110 to remote computing devices 112, such as a plurality of computing devices in a simulation cluster. For example, the surface equipment 104 may communicate data using a satellite network to computing devices 112 supporting a remote team monitoring and assisting in the creation of the well 106 and other wells in other locations. Depending on the communications infrastructure available at the wellsite, various communications equipment and techniques (cellular, satellite, wired Internet connection, etc.) may be used to communicate data from the surface equipment 104 to the remote computing devices 112. In some embodiments, the surface equipment 104 sends data from measurements taken at the surface and measurements taken downhole by the downhole equipment 108 to the remote computing devices 112. In some embodiments, the data from the surface equipment 104 is received at a remote server configured to generate an influx monitoring envelope for the well 106.

During the well construction process, a variety of operations (such as cementing, wireline evaluation, testing, etc.) may also be conducted. In such embodiments, the data collected by tools and sensors and used for reasons such as reservoir characterization may also be collected and transmitted by the surface equipment 104.

In FIG. 1, the well 106 includes a substantially horizontal portion (e.g., lateral portion) that may intersect with one or more fractures. For example, a well in a shale formation may pass through natural fractures, artificial fractures (e.g., hydraulic fractures), or a combination thereof. Such a well may be constructed using directional drilling techniques as described herein. However, these same techniques may be used in connection with other types of directional wells (such as slant wells, S-shaped wells, deep inclined wells, and others) and are not limited to horizontal wells.

FIG. 2 shows an example of a wellsite system 200 (e.g., at a wellsite that may be onshore or offshore). As shown, the wellsite system 200 may include a mud tank 201 for holding mud and other material (e.g., where mud may be a drilling fluid), a suction line 203 that serves as an inlet to a mud pump 204 for pumping mud from the mud tank 201 such that mud flows to a vibrating hose 206, a drawworks 207 for winching drill line or drill lines 212, a standpipe 208 that receives mud from the vibrating hose 206, a kelly hose 209 that receives mud from the standpipe 208, a gooseneck or goosenecks 210, a traveling block 211, a crown block 213 for carrying the traveling block 211 via the drill line or drill lines 212, a derrick 214, a kelly 218 or a top drive 240, a kelly drive bushing 219, a rotary table 220, a drill floor 221, a bell nipple 222, one or more blowout preventors (BOPs) 223, a drillstring 225, a drill bit 226, a casing head 227 and a flow pipe 228 that carries mud and other material to, for example, the mud tank 201.

In the example system of FIG. 2, a borehole 232 is formed in subsurface formations 230 by rotary drilling; noting that various example embodiments may also use one or more directional drilling techniques, equipment, etc.

As shown in the example of FIG. 2, the drillstring 225 is suspended within the borehole 232 and has a drillstring assembly 250 that includes the drill bit 226 at its lower end. As an example, the drillstring assembly 250 may be a bottom hole assembly (BHA).

The wellsite system 200 may provide for operation of the drillstring 225 and other operations. As shown, the wellsite system 200 includes the traveling block 211 and the derrick 214 positioned over the borehole 232. As mentioned, the wellsite system 200 may include the rotary table 220 where the drillstring 225 pass through an opening in the rotary table 220.

As shown in FIG. 2, the wellsite system 200 may include the kelly 218 and associated components, etc., or a top drive 240 and associated components. Where the wellsite system 200 includes the kelly 218, the kelly 218 may be a square or hexagonal metal/alloy bar with a hole drilled therein that serves as a mud flow path. The kelly 218 may be used to transmit rotary motion from the rotary table 220 via the kelly drive bushing 219 to the drillstring 225, while allowing the drillstring 225 to be lowered or raised during rotation. The kelly 218 may pass through the kelly drive bushing 219, which may be driven by the rotary table 220. The rotary table 220 may include a master bushing that operatively couples to the kelly drive bushing 219 such that rotation of the rotary table 220 may turn the kelly drive bushing 219 and hence the kelly 218. The kelly drive bushing 219 may include an inside profile matching an outside profile (e.g., square, hexagonal, etc.) of the kelly 218; however, with slightly larger dimensions so that the kelly 218 may freely move up and down inside the kelly drive bushing 219.

In embodiments where the wellsite system 200 includes a top drive 240, the top drive 240 may provide functions performed by a kelly and a rotary table. The top drive 240 may turn the drillstring 225. As an example, the top drive 240 may include one or more motors (e.g., electric and/or hydraulic) connected with appropriate gearing to a short section of pipe called a quill, that in turn may be screwed into a saver sub or the drillstring 225 itself. The top drive 240 may be suspended from the traveling block 211, so the rotary mechanism is free to travel up and down the derrick 214. As an example, a top drive 240 may allow for drilling to be performed with more joint stands than a kelly/rotary table approach.

The mud tank 201 may hold a drilling fluid, which may also be referred to as drilling mud, or simply mud. As an example, a wellbore may be drilled to produce fluid, inject fluid or both (e.g., hydrocarbons, minerals, water, etc.).

In FIG. 2, the drillstring 225 (e.g., including one or more downhole tools) may be composed of a series of pipes threadably connected together to form a long tube with the drill bit 226 at the lower end thereof. As the drillstring 225 is advanced into a wellbore for drilling, at some point in time prior to or coincident with drilling, the mud may be pumped by the pump 204 from the mud tank 201 (e.g., or other source) via the lines 206, 208 and 209 to a port of the kelly 218 or, for example, to a port of the top drive 240. The mud may then flow via a passage (e.g., or passages) in the drillstring 225 and out of ports located on the drill bit 226 (see, e.g., a directional arrow). As the mud exits the drillstring 225 via ports in the drill bit 226, it may then circulate upwardly through an annular region between an outer surface(s) of the drillstring 225 and surrounding wall(s) (e.g., open borehole, casing, etc.), as indicated by directional arrows. In such a manner, the mud lubricates the drill bit 226 and carries heat energy (e.g., frictional or other energy) and formation cuttings to the surface where the mud (e.g., and cuttings) may be returned to the mud tank 201, for example, for recirculation (e.g., with processing to remove cuttings, etc.).

The mud pumped by the pump 204 into the drillstring 225 may, after exiting the drillstring 225, form a mudcake that lines the wellbore which, among other functions, may reduce friction between the drillstring 225 and surrounding wall(s) (e.g., borehole, casing, etc.). A reduction in friction may facilitate advancing or retracting the drillstring 225. During a drilling operation, the entire drillstring 225 may be pulled from a wellbore and optionally replaced, for example, with a new or sharpened drill bit, a smaller diameter drillstring, etc. As mentioned, the act of pulling a drillstring out of a hole or replacing it in a hole is referred to as tripping. A trip may be referred to as an upward trip or an outward trip or as a downward trip or an inward trip depending on trip direction.

As an example, during a downward trip, pumping of the mud commences to lubricate the drill bit 226 upon arrival of the drill bit 226 of the drillstring 225 at a bottom of a wellbore. As mentioned, the mud may be pumped by the pump 204 into a passage of the drillstring 225 and, upon filling of the passage, the mud may be used as a transmission medium to transmit energy, for example, energy that may encode information as in mud-pulse telemetry.

As an example, mud-pulse telemetry equipment may include a downhole device configured to effect changes in pressure in the mud to create an acoustic wave or waves upon which information may modulated. In such an example, information from downhole equipment (e.g., one or more modules of the drillstring 225) may be transmitted uphole to an uphole device, which may relay such information to other equipment for processing, control, etc.

As an example, telemetry equipment may operate via transmission of energy via the drillstring 225 itself. For example, consider a signal generator that imparts coded energy signals to the drillstring 225 and repeaters that may receive such energy and repeat it to further transmit the coded energy signals (e.g., information, etc.)

As an example, the drillstring 225 may be fitted with telemetry equipment 252 that includes a rotatable drive shaft, a turbine impeller mechanically coupled to the drive shaft such that the mud may cause the turbine impeller to rotate, a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes said modulator rotor to rotate, a modulator stator mounted adjacent to or proximate to the modulator rotor such that rotation of the modulator rotor relative to the modulator stator creates pressure pulses in the mud, and a controllable brake for selectively braking rotation of the modulator rotor to modulate pressure pulses. In such example, an alternator may be coupled to the aforementioned drive shaft where the alternator includes at least one stator winding electrically coupled to a control circuit to selectively short the at least one stator winding to electromagnetically brake the alternator and thereby selectively brake rotation of the modulator rotor to modulate the pressure pulses in the mud.

In the example of FIG. 2, an uphole control and/or data acquisition system 262 may include circuitry to sense pressure pulses generated by telemetry equipment 252 and, for example, communicate sensed pressure pulses or information derived therefrom for process, control, etc.

The assembly 250 of the illustrated example includes a logging-while-drilling (LWD) module 254, a measurement-while-drilling (MWD) module 256, an optional module 258, a rotary-steerable system (RSS) and/or motor 260, and the drill bit 226. Such components or modules may be referred to as tools where a drillstring may include a plurality of tools.

The RSS may be utilized for directional drilling, which includes drilling into the Earth to form a deviated bore such that the trajectory of the bore deviates from vertical along one or more portions of the bore. As an example, consider a target that is located at a lateral distance from a surface location where a rig may be stationed. In such an example, drilling may commence with a vertical portion and then deviate from vertical such that the bore is aimed at the target and, eventually, reaches the target. Directional drilling may be implemented where a target may be inaccessible from a vertical location at the surface of the Earth, where material exists in the Earth that may impede drilling or otherwise be detrimental (e.g., consider a salt dome, etc.), where a formation is laterally extensive (e.g., consider a relatively thin yet laterally extensive reservoir), where multiple bores are to be drilled from a single surface bore, where a relief well is desired, etc.

One approach to directional drilling involves a mud motor; however, a mud motor may present some challenges depending on factors such as rate of penetration (ROP), transferring weight to a bit (e.g., weight on bit, WOB) due to friction, etc. A mud motor may be a positive displacement motor (PDM) that operates to drive a bit (e.g., during directional drilling, etc.). A PDM operates as drilling fluid is pumped through it where the PDM converts hydraulic power of the drilling fluid into mechanical power to cause the bit to rotate.

As an example, a PDM may operate in a combined rotating mode where surface equipment is utilized to rotate a bit of a drillstring (e.g., a rotary table, a top drive, etc.) by rotating the entire drillstring and where drilling fluid is utilized to rotate the bit of the drillstring. In such an example, a surface RPM (SRPM) may be determined by use of the surface equipment and a downhole RPM of the mud motor may be determined using various factors related to flow of drilling fluid, mud motor type, etc. As an example, in the combined rotating mode, bit RPM may be determined or estimated as a sum of the SRPM and the mud motor RPM, assuming the SRPM and the mud motor RPM are in the same direction.

As an example, a PDM mud motor may operate in a so-called sliding mode, when the drillstring is not rotated from the surface. In such an example, a bit RPM may be determined or estimated based on the RPM of the mud motor.

A RSS may drill directionally where there is continuous rotation from surface equipment, which may alleviate the sliding of a steerable motor (e.g., a PDM). A RSS may be deployed when drilling directionally (e.g., deviated, horizontal, or extended-reach wells). A RSS may aim to minimize interaction with a borehole wall, which may help to preserve borehole quality. A RSS may aim to exert a relatively consistent side force akin to stabilizers that rotate with the drillstring or orient the bit in the desired direction while continuously rotating at the same number of rotations per minute as the drillstring.

The LWD module 254 may be housed in a suitable type of drill collar and may contain one or a plurality of selected types of logging tools. It will also be understood that more than one LWD and/or MWD module may be employed, for example, as represented at by the module 256 of the drillstring assembly 250. Where the position of an LWD module is mentioned, as an example, it may refer to a module at the position of the LWD module 254, the module 256, etc. An LWD module may include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the illustrated example, the LWD module 254 may include a seismic measuring device.

The MWD module 256 may be housed in a suitable type of drill collar and may contain one or more devices for measuring characteristics of the drillstring 225 and the drill bit 226. As an example, an MWD tool may include equipment for generating electrical power, for example, to power various components of the drillstring 225. As an example, the MWD tool may include the telemetry equipment 252, for example, where the turbine impeller may generate power by flow of the mud; it being understood that other power and/or battery systems may be employed for purposes of powering various components. As an example, the MWD module 256 may include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.

FIG. 2 also shows some examples of types of holes that may be drilled. For example, consider a slant hole 272, an S-shaped hole 274, a deep inclined hole 276 and a horizontal hole 278.

As an example, a drilling operation may include directional drilling where, for example, at least a portion of a well includes a curved axis. For example, consider a radius that defines curvature where an inclination with regard to the vertical may vary until reaching an angle between about 30 degrees and about 60 degrees or, for example, an angle to about 90 degrees or possibly greater than about 90 degrees.

As an example, a directional well may include several shapes where each of the shapes may aim to meet particular operational demands. As an example, a drilling process may be performed on the basis of information as and when it is relayed to a drilling engineer. As an example, inclination and/or direction may be modified based on information received during a drilling process.

As an example, deviation of a bore may be accomplished in part by use of a downhole motor and/or a turbine. As to a motor, for example, a drillstring may include a positive displacement motor (PDM).

As an example, a system may be a steerable system and include equipment to perform method such as geosteering. As mentioned, a steerable system may be or include an RSS. As an example, a steerable system may include a PDM or of a turbine on a lower part of a drillstring which, just above a drill bit, a bent sub may be mounted. As an example, above a PDM, MWD equipment that provides real time or near real time data of interest (e.g., inclination, direction, pressure, temperature, real weight on the drill bit, torque stress, etc.) and/or LWD equipment may be installed. As to the latter, LWD equipment may make it possible to send to the surface various types of data of interest, including for example, geological data (e.g., gamma ray log, resistivity, density and sonic logs, etc.).

The coupling of sensors providing information on the course of a well trajectory, in real time or near real time, with, for example, one or more logs characterizing the formations from a geological viewpoint, may allow for implementing a geosteering method. Such a method may include navigating a subsurface environment, for example, to follow a desired route to reach a desired target or targets.

As an example, a drillstring may include an azimuthal density neutron (ADN) tool for measuring density and porosity; a MWD tool for measuring inclination, azimuth and shocks; a compensated dual resistivity (CDR) tool for measuring resistivity and gamma ray related phenomena; one or more variable gauge stabilizers; one or more bend joints; and a geosteering tool, which may include a motor and optionally equipment for measuring and/or responding to one or more of inclination, resistivity and gamma ray related phenomena.

As an example, geosteering may include intentional directional control of a wellbore based on results of downhole geological logging measurements in a manner that aims to keep a directional wellbore within a desired region, zone (e.g., a pay zone), etc. As an example, geosteering may include directing a wellbore to keep the wellbore in a particular section of a reservoir, for example, to minimize gas and/or water breakthrough and, for example, to maximize economic production from a well that includes the wellbore.

Referring again to FIG. 2, the wellsite system 200 may include one or more sensors 264 that are operatively coupled to the control and/or data acquisition system 262. As an example, a sensor or sensors may be at surface locations. As an example, a sensor or sensors may be at downhole locations. As an example, a sensor or sensors may be at one or more remote locations that are not within a distance of the order of about one hundred meters from the wellsite system 200. As an example, a sensor or sensor may be at an offset wellsite where the wellsite system 200 and the offset wellsite are in a common field (e.g., oil and/or gas field).

As an example, one or more of the sensors 264 may be provided for tracking pipe, tracking movement of at least a portion of a drillstring, etc.

As an example, the system 200 may include one or more sensors 266 that may sense and/or transmit signals to a fluid conduit such as a drilling fluid conduit (e.g., a drilling mud conduit). For example, in the system 200, the one or more sensors 266 may be operatively coupled to portions of the standpipe 208 through which mud flows. As an example, a downhole tool may generate pulses that may travel through the mud and be sensed by one or more of the one or more sensors 266. In such an example, the downhole tool may include associated circuitry such as, for example, encoding circuitry that may encode signals, for example, to reduce demands as to transmission. As an example, circuitry at the surface may include decoding circuitry to decode encoded information transmitted at least in part via mud-pulse telemetry. As an example, circuitry at the surface may include encoder circuitry and/or decoder circuitry and circuitry downhole may include encoder circuitry and/or decoder circuitry. As an example, the system 200 may include a transmitter that may generate signals that may be transmitted downhole via mud (e.g., drilling fluid) as a transmission medium.

As an example, one or more portions of a drillstring may become stuck. The term stuck may refer to one or more of varying degrees of inability to move or remove a drillstring from a bore. As an example, in a stuck condition, it might be possible to rotate pipe or lower it back into a bore or, for example, in a stuck condition, there may be an inability to move the drillstring axially in the bore, though some amount of rotation may be possible. As an example, in a stuck condition, there may be an inability to move at least a portion of the drillstring axially and rotationally.

As to the term “stuck pipe”, this may refer to a portion of a drillstring that cannot be rotated or moved axially. As an example, a condition referred to as “differential sticking” may be a condition whereby the drillstring cannot be moved (e.g., rotated or reciprocated) along the axis of the bore. Differential sticking may occur when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drillstring. Differential sticking may have time and financial cost.

As an example, a sticking force may be a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon. This means that a relatively low differential pressure (delta p) applied over a large working area may be just as effective in sticking pipe as may a high differential pressure applied over a small area.

As an example, a condition referred to as “mechanical sticking” may be a condition where limiting or prevention of motion of the drillstring by a mechanism other than differential pressure sticking occurs. Mechanical sticking may be caused, for example, by one or more of junk in the hole, wellbore geometry anomalies, cement, keyseats or a buildup of cuttings in the annulus.

In some embodiments, the wellsite system 200 includes a managed pressure drilling system and related components. For example, the wellsite system 200 may include a backpressure pump in fluid communication with the mud tank 201 and the flow pipe 228. The backpressure pump may be configured to provide a backpressure to the drilling fluid (the mud) in the wellbore, such as in an annular space between the drillstring 225 and the surfaces of the subsurface formation 230 defining the borehole 232.

The wellsite system 200 may further include a drilling fluid choke valve in fluid communication with the mud tank 201 and the flow pipe 228. In operation, the drilling fluid in the flow pipe 228 flows through the drilling fluid choke valve prior to entering the mud tank 201.

In some embodiments, the wellsite system 200 includes sensors (in addition to those previously described) for operating the wellsite system 200. For example, the wellsite system 200 may include one or more of (e.g., each of) flowmeter in the flow pipe 228 and/or a choke line configured to measure a flow of fluid (e.g., the drilling fluid) returning to the mud tank 201, a flowmeter in the vibrating hose 206 configured to measure a flowrate of the drilling fluid from the mud pump 204, a pressure sensor configured to measure the surface pressure of the drilling fluid at the surface (e.g., before the choke, after the choke), a pressure sensor at the casing shoe configured to measure a pressure of the drilling fluid at the casing shoe, a depth sensor configured to measure the depth of the casing shoe, a depth sensor configured to measure a depth of the drill bit 226, a temperature sensor in the wellbore (e.g., proximate the casing shoe, proximate the drill bit 226, and/or at one or more additional locations along the borehole 232).

As described above with reference to FIG. 1, the wellsite system 200 may include or may be associated with the remote computing device 112 (FIG. 1).

FIG. 3 is a schematic view of such a computing or processor system 300, according to an embodiment. The processor system 300 may include one or more processors 302 of varying core configurations (including multiple cores) and clock frequencies. The one or more processors 302 may be operable to execute instructions, apply logic, etc. It will be appreciated that these functions may be provided by multiple processors or multiple cores on a single chip operating in parallel and/or communicably linked together. In at least one embodiment, the one or more processors 302 may be or include one or more GPUs.

The processor system 300 may also include a memory system, which may be or include one or more memory devices and/or computer-readable media 304 of varying physical dimensions, accessibility, storage capacities, etc. such as flash drives, hard drives, disks, random access memory, etc., for storing data, such as images, files, and program instructions for execution by the processor 302. In an embodiment, the computer-readable media 304 may store instructions that, when executed by the processor 302, are configured to cause the processor system 300 to perform operations. For example, execution of such instructions may cause the processor system 300 to implement one or more portions and/or embodiments of the method(s) described above.

The processor system 300 may also include one or more network interfaces 306. The network interfaces 306 may include any hardware, applications, and/or other software. Accordingly, the network interfaces 306 may include Ethernet adapters, wireless transceivers, PCI interfaces, and/or serial network components, for communicating over wired or wireless media using protocols, such as Ethernet, wireless Ethernet, etc.

As an example, the processor system 300 may be a mobile device that includes one or more network interfaces for communication of information. For example, a mobile device may include a wireless network interface (e.g., operable via one or more IEEE 802.11 protocols, ETSI GSM, BLUETOOTH®, satellite, etc.). As an example, a mobile device may include components such as a main processor, memory, a display, display graphics circuitry (e.g., optionally including touch and gesture circuitry), a SIM slot, audio/video circuitry, motion processing circuitry (e.g., accelerometer, gyroscope), wireless LAN circuitry, smart card circuitry, transmitter circuitry, GPS circuitry, and a battery. As an example, a mobile device may be configured as a cell phone, a tablet, etc. As an example, a method may be implemented (e.g., wholly or in part) using a mobile device. As an example, a system may include one or more mobile devices.

The processor system 300 may further include one or more peripheral interfaces 308, for communication with a display, projector, keyboards, mice, touchpads, sensors, other types of input and/or output peripherals, and/or the like. In some implementations, the components of processor system 300 need not be enclosed within a single enclosure or even located in close proximity to one another, but in other implementations, the components and/or others may be provided in a single enclosure. As an example, a system may be a distributed environment, for example, a so-called “cloud” environment where various devices, components, etc. interact for purposes of data storage, communications, computing, etc. As an example, a method may be implemented in a distributed environment (e.g., wholly or in part as a cloud-based service).

As an example, information may be input from a display (e.g., a touchscreen), output to a display or both. As an example, information may be output to a projector, a laser device, a printer, etc. such that the information may be viewed. As an example, information may be output stereographically or holographically. As to a printer, consider a 2D or a 3D printer. As an example, a 3D printer may include one or more substances that may be output to construct a 3D object. For example, data may be provided to a 3D printer to construct a 3D representation of a subterranean formation. As an example, layers may be constructed in 3D (e.g., horizons, etc.), geobodies constructed in 3D, etc. As an example, holes, fractures, etc., may be constructed in 3D (e.g., as positive structures, as negative structures, etc.)

The memory device 304 may be physically or logically arranged or configured to store data on one or more storage devices 310. The storage device 310 may include one or more file systems or databases in any suitable format. The storage device 310 may also include one or more software programs 312, which may contain interpretable or executable instructions for performing one or more of the disclosed processes. When requested by the processor 302, one or more of the software programs 312, or a portion thereof, may be loaded from the storage devices 310 to the memory devices 304 for execution by the processor 302.

Those skilled in the art will appreciate that the above-described componentry is merely one example of a hardware configuration, as the processor system 300 may include any type of hardware components, including any accompanying firmware or software, for performing the disclosed implementations. The processor system 300 may also be implemented in part or in whole by electronic circuit components or processors, such as application-specific integrated circuits (ASICs) or field-programmable gate arrays (FPGAs).

The processor system 300 may be configured to receive a directional drilling well plan 320. As discussed above, a well plan is the description of the proposed wellbore to be used by the drilling team in drilling the well. The well plan typically includes information about the shape, orientation, depth, completion, and evaluation along with information about the equipment to be used, actions to be taken at different points in the well construction process, and other information the team planning the well believes will be relevant/helpful to the team drilling the well. A directional drilling well plan will also include information about how to steer and manage the direction of the well.

The processor system 300 may be configured to receive drilling data 322. The drilling data 322 may include data collected by one or more sensors associated with surface equipment or with downhole equipment. The drilling data 322 may include information such as data relating to the position of the BHA (such as survey data or continuous position data), drilling parameters (such as weight on bit (WOB), rate of penetration (ROP), torque, or others), text information entered by individuals working at the wellsite, or other data collected during the construction of the well.

In one embodiment, the processor system 300 is part of a rig control system (RCS) for the rig. In another embodiment, the processor system 300 is a separately installed computing unit including a display that is installed at the rig site and receives data from the RCS. In such an embodiment, the software on the processor system 300 may be installed on the computing unit, brought to the wellsite, and installed and communicatively connected to the rig control system in preparation for constructing the well or a portion thereof.

In another embodiment, the processor system 300 may be at a location remote from the wellsite and receives the drilling data 322 over a communications medium using a protocol such as well-site information transfer specification or standard (WITS) and markup language (WITSML). In such an embodiment, the software on the processor system 300 may be a web-native application that is accessed by users using a web browser. In such an embodiment, the processor system 300 may be remote from the wellsite where the well is being constructed, and the user may be at the wellsite or at a location remote from the wellsite.

According to embodiments of the disclosure, the well control workflow may be automated using an integration of a dynamic pressure model and a transient multiphase model. In some embodiments, an output of the dynamic pressure model is provided to the transient multiphase model, which calculates the influx management envelope. In some embodiments, the influx management envelope is displayed to a user, such as on an output device (e.g., a user interface, a monitor, etc.).

Reducing the time required to fully plan a well has been a target for the drilling industry during the past decade and lately, with a specific metric: to plan a well in a day. As part of an innovative digital well construction planning solution the collaboration and coherency challenges has been solved making this a realistic target in the near future. This is valid for most projects, but particularly in challenging multidisciplinary projects. Even more important than efficient planning is the safety of the operations and reducing the potential well control risk. For well control operations, uncertainties in the mud density and downhole pressure boundaries have presented issues in determining the influx management envelope. The single bubble kick tolerance process is the most common way to evaluate well control risk.

However, the wellbore conditions are not steady state or single bubble. The wellbore conditions are continuously changing, impacted by transient with different characteristics, multiphase flow conditions with phase transitions, reservoir interaction, original and induced stresses disturbances and several operational changes. Therefore, in order to correctly understand and evaluate the risk of the operation, transient multiphase modeling is required.

In this regard, a well control engineer is faced with two challenges that does not seem to match: first, there is constant push for cost reductions with more efficient solutions. Secondly, there is a continuous focus on minimizing the well control risk. The well control engineer has—up to now—been faced with a dilemma, to either choose the automated well planning systems with coherent data and a reduction in risk of human errors or use expert technology and in many cases external resources and services to fully assess well control risk. This will give a better understanding of the well control risk, but it will effectively miss the targeted efficiency and cost reduction.

Capturing all the transients in the well is important to accurately reproduce the wellbore conditions during a well control incident. The multiphase flow conditions that is a consequence of the reservoir influx together with complex pressure, volume & temperature (PVT) conditions and varying temperature introduces transients that also needs to be considered and modeled. The engine described herein facilitates consideration of each of the foregoing to generate the influx management envelope.

Most kick incidents will be solved by circulating the influx out of the well using Drillers circulation. This is a standardized procedure, in particular in the planning phase, and this enables the definition of a workflow scope based on the operational sequence and events of Drillers method. With a MPD system, the influx may be controlled or stopped by adding surface back pressure. Small volumes may be circulated to the surface without switching to conventional well control and Drillers method.

Automation is a fundamental requirement for implementing a workflow like this into a modern well planning system. A key part of such systems is the ability to recalculate or update all calculations when the project context is changing. Drillers method includes well defined operational periods and events and a set of controllers are defined to automatically advance the workflow forward as the different events occur. This makes the workflow possible to run without any form of user interaction (FIG. 4). The workflow design and automation make it very easy to use, and the user configuration is requiring operational data similar to the requirements of the much more basic single bubble calculations.

The workflow runs several heavy numerical simulations with parallelization where the computing power offered by the cloud deployment is automatically balanced to deliver a reasonable performance.

The driller's method is one of several methods to regain control of the well during a well control scenario and is one of the most widely used worldwide. The main concept is to kill the well while maintaining bottom hole pressure constant. The driller's method is achieved by a first circulation to remove the influx, followed by a second circulation to kill the well with a heavier mud.

During the first circulation, the bottom hole pressure is kept constant by maintaining drill pipe pressure constant while circulating until the influx (also known as kick) is fully displaced from the annulus. The operational procedure of ramping up flowrate while maintaining the choke pressure constant until initial circulating pressure is established is in particular important to consider for proper evaluation of the margins. After the kick is totally removed from the well, when the well is shut-in, drill pipe and casing pressure will be similar. For the second circulation, in order to maintain constant bottom hole pressure, casing pressure is held constant while circulating kill mud to the bit. Once the kill mud passes the bit, the drill pipe pressure will be held constant until the kill weight mud is on surface and there is no sign of influx in the annulus. Then, the pumping operation is shut down to observe the behavior of the drill pipe and casing pressures. If the well control scenario is under control, both drill pipe and casing pressures will be zero, otherwise there is still an influx in the well and the operation must be repeated (FIG. 5).

The use of dynamic modeling versus single bubble kick tolerance provides advantages when determining the influx management envelope. Dynamic models have traditionally been more complex to use, but they are providing a significantly better insight in the risk scenarios and thereby offer a better basis for planning and design. In the workflow described in this paper, the focus will be on the differences between different dynamic models. The engine used in the new workflow will be compared to one of the market leading dynamic solutions for well control. For simpler understanding, the engine used as part of the new automated workflow will be referred to as “new model” and the previous solution will be referred to as “old model”.

In addition to the automation of the workflow, there are significant differences between the two models with respect to modeling features. The new model is historically used and well established in the industry for modelling flow assurance and well production, where flow dynamics and fluid phase behavior are of critical importance. This makes the model well suited for adaption to well control specific scenarios. The model is fully transient—including acceleration effects (pressure waves), dynamic temperature and full compositional tracking. A controller network may be defined to accurately simulate the operational procedure as it is performed on the rig. The old model is already well established as an expert tool for well control in the industry. Both models are flexible and may be used to simulate a variety of scenarios. The automated workflow is defined with kick tolerance evaluation as the only objective and this simplifies the use of the workflow to a level comparable in use to single bubble models, even when the reality is that the most complex technology is used.

An example to compare both models based on a high pressure and high temperature (HPHT) well (real case) is provided herewith. The well in question has total measured depth (MD) of approximately of 5600 m and the 9⅝″ casing shoe is set at approx. 4400 m MD. The mud density is 2.05 sg (specific gravity). The same parameters have been used in both models and the kick tolerance has been evaluated for the well.

FIG. 6 and FIG. 7 present the comparisons of well pressures at bottomhole and at casing shoe depths and illustrate the obvious differences between the two solutions. The main reason for the difference is the difference in simulation procedure. In the new model, the procedure is more closely reflecting the actual operational procedure—keeping the choke pressure constant while the pump rate is ramped up to the slow circulation rate and then switching to keeping the bottomhole pressure constant. This means that the new model includes the equivalent circulation density (ECD) contribution. The multiphase model has been compared to a single-phase dynamic hydraulics model and handles complex non-Newtonian rheology definition with the same accuracy. In the old model this pressure needs to be manually added in order to compare the two. For experienced users, this is done as a routine, but failing to include this contribution may result in misinterpreting the actual safety margins and well control risk.

The difference in choke control is illustrated in FIG. 8. In the new model, the choke pressure is kept constant as the slow circulation rate is established and thereafter it switches to constant bottomhole pressure mode.

The new model is represents a better modeling of the operational procedure than the old model. The old model requires the user to evaluate and compensate for the annulus friction. On the other hand, the new model guides the user to do it right the first time with less configuration options. This makes the new model a better solution for regular users, not demanding the same expert level.

The other significant difference that may be observed between the two models are related to PVT modeling and temperature handling. The new model combines a fully compositional equations of state (EOS) PVT model with transient temperature modeling which combined, impact the transition from dissolved to free gas.

FIG. 9 and FIG. 10 show the difference in pit gain and gas flowrate out between the two models. The circulation is started at the same point for both models (around 140 minutes simulation time). There are some significant differences between the two solutions as the old model uses a front tracking technique combined with a coarse grid, while the new model combines a finer grid with a second order mass transfer. In addition, the full compositional tracking is considering the compositional change of the phases, including the solution into the mud base oil, as the pressure, temperature and distribution is changing during the course of the simulation. The compositional tracking will have significance for the dynamic behavior of the dissolution and breakout of free gas as dictated by pressure and temperature. These model differences may explain the differences in the arrival and progression of the pit gain and gas flowrate as it reaches surface. FIG. 11 illustrates the distribution of free and dissolved gas for the two models. The blue colors are representing the old model, while the red curves represent the new model. One obvious difference is that the old model indicates an amount of free gas initially, while the new model only shows liquid/dissolved gas (as would be expected at the simulated temperature and pressure conditions). The behavior of the new model seems to be representing the actual physics better. The free gas also disappears in the old model, and for a long period both models show that all gas is dissolved. The gas in the old model is more stretched out, while the new model shows that the gas appears to be more concentrated. It is also worth noting that free gas breakout appears at deeper depth in the well with the new model.

The sharper peak and the differences in distribution of the new model indicates that the solution technique in the new model prevents any issues with numerical dispersion and that the resolution is better than in the old model. Accurate estimate of pit gain and maximum flowrate is important as this information is used in designing the mud gas separator and ensuring that the rig has sufficient gas handling capacity for the maximum kick sizes.

By looking at the pressure plots and neglecting the difference in operational procedure, both models show reasonable results. The difference in bottomhole pressure is mainly caused by the ECD contribution accounted for in the new model. The choke regulation from a stable slow circulation rate has been established is also fairly similar between the two models.

All the modeling improvements lead to numerically heavy simulations that may easily become a showstopper without the strong focus on performance in the work associated with the new model. Optimizing the algorithms, using strong domain knowledge to simplify the complexity by making smart and relevant assumptions and utilizing the computing power and the ability to run simulations in parallel, have been instrumental in achieving the performance observed with the new workflow.

Automating the workflow and introduction into a modern well planning system running on consistent and coherent dataset simplifies the use and significantly reduces the manual work often associated with keeping external expert solution up to date. In complex, multidisciplinary projects there are frequent changes that often leads to frequent iterations in well control and kick tolerance evaluations when using external software solutions. When everything is integrated and automated, there is no additional effort to run additional simulations and the results will be available as soon as the simulations are finished. Typically, an evaluation of the kick tolerance for all sections of a well with some volume sensitivities will be available within 10 to 15 minutes (FIG. 12). This setup is scalable with same computational time expectancy for additional sensitivities and multiple concept evaluations or projects. Running this manually could take days if there are several significant changes to the project.

An important aspect of the efficiency gain is that dynamic modeling does not need to be limited to the most complex and tight wells. The simplicity of the workflow makes it possible to use dynamic modeling as a standard for most wells and thereby improve the safety of the design and planned operations.

The results from the old and the new dynamic model are in general quite close. A couple of well documented differences have been observed and explained. The fact that the new model is more closely replicating the operational sequence as it is performed on the rig introduces some differences. The friction pressure is included in the procedure in the new workflow. The same consideration requires some manual steps and a detailed understanding of the simulation vs operational procedure if done with the old model. Apart from this difference, the pressures trends are quite similar in both models.

The combination of transient temperature and the improved PVT model in the new model impacts the phase behavior in the wellbore. The models account for effects that are neglected in the old model—so it is expected that there will be some differences when it comes to gas distribution and free gas break out position. This has significance for the pit gain volume trend and the surface flowrates. Due to the more advanced model, the new solution is expected to be the most accurate—and the results should be trusted. Again, even if differences are observed, the trends are similar, and both models are delivering good results.

The efficiency gain by using the new workflow compared to the previous expert tool is difficult to quantify. The time it takes to run and rerun the workflow in case of changes in the project is quite well known. It may be impacted by the cluster size and scalability if the resources are shared by many projects, but in theory it should not be much impacted. How long an iteration takes in the old system is highly dependent on the type of changes in the project. If it is only one team (e.g. drilling fluid) that is changed, it may be easy to update and re-run. The complexity is much worse if changes are made in several teams, so that a manual synchronization and data quality control is required. An iteration may take a few hours, but if the project is big with several changes ongoing in parallel, it may be challenging and time consuming to make sure that all data are synchronized.

With the usage of automation and optimization processes as part of this analysis, it is possible to include workflows using advanced multiphase technology into modern digital well planning systems. The following summarize the key findings:

The model described herein delivers superior performance and there is no contradiction between efficiency and accuracy. The most advanced technology secures best possible evaluation of the well control risk and automation enables this technology for all projects.

The described model uses a powerful engine that may run consistently in the cloud and operations on an automated procedure.

The described model simulates physical processes neglected in most other models. The main trends from an available expert tool are reproduced. The differences that are observed are related to model features that are included in the new model and neglected in the old model.

The new model is therefore overall seen as a significant improvement. With automation, the new model is delivering better performance than the old, regardless of the use of a more advanced technology.

FIG. 13 is a simplified flow diagram illustrating a method 1300 of generating an influx management envelope, according to at least one embodiment of the disclosure. The method 1300 includes generating a dynamic pressure profile of a wellbore for a drilling fluid having a density using a dynamic pressure model, as shown in act 1302. In some embodiments, the dynamic pressure model receives inputs of one or more wellbore properties, wellbore conditions, or formation conditions. For example, the inputs to the dynamic pressure model may include one or more of a temperature of the wellbore at one or more locations along the wellbore, a pressure of the drilling fluid within the wellbore at one or more locations within the wellbore, the flowrate of the drilling fluid within the wellbore, the choke pressure of the drilling fluid, the bottomhole pressure of the drilling fluid, the depth of the wellbore, the depth of the drill string, the depth of the casing shoe, the diameter of the wellbore, the diameter of the drill string, the diameter of the casing, the pore pressure of the earth formation, the fraction pressure of the earth formation, or combinations thereof. In addition, the input includes a density of the drilling fluid.

Based on the inputs, the dynamic pressure model may determine one or more of the equivalent circulating density profile of the drilling fluid in the wellbore, the equivalent static density profile of the drilling fluid, or the temperature profile of the wellbore and/or drilling fluid within the wellbore.

In some embodiments, the dynamic pressure model determines the pressure profile of the drilling fluid throughout the wellbore. The dynamic pressure model may account for friction loss of the drilling fluid (e.g., caused by friction between the drilling fluid and the sidewalls of the earth formation defining the wellbore, friction between the drilling fluid and the drill string and/or casing, and the flowrate of the drilling fluid).

Act 1302 may be performed remotely from the wellbore. In some embodiments, act 1302 is performed remotely from the wellbore with information received at or proximate the wellbore (e.g., information about one or more of the temperature, pressure, or earth formation, drilling fluid). The information may be received (e.g., measured) by one or more sensors. In some embodiments, act 1302 is performed via cloud computing using a simulation cluster.

In some embodiments, act 1302 includes determining the dynamic pressure profile of different drilling fluids having different densities simultaneously (e.g., substantially simultaneously). For example, act 1302 may include determining the dynamic pressure profile of a first drilling fluid using the dynamic pressure model, and substantially concurrently and in parallel, determining the dynamic pressure profile of second drilling fluid having a different density than the first drilling fluid using the dynamic pressure model.

Responsive to determining the pressure profile of the drilling fluid, the method 1300 further includes receiving the output from the dynamic pressure model with a transient multiphase model and determining a post influx surface pressure of the drilling fluid for a given influx volume, as shown in act 1304. For example, for each of the drilling fluids for which a dynamic pressure profile was determining in act 1302, transient multiphase model may use the dynamic pressure profile and determine the post influx surface pressure of the drilling fluid for each of a plurality of influx volumes. The transient multiphase model may account for transient phase changes of the influx (kick) between the liquid phase, the liquid-gas phase, and the gas phase based on the equations of state of the transient multiphase model and the pressure profile determined during act 1302. In some embodiments, act 1304 is performed via a simulation cluster such that multiple iterations may be performed simultaneously. For example, the post influx surface pressure of the drilling fluid may be determined for a plurality of different influx volumes for the drilling fluid substantially simultaneously (e.g., in parallel) since act 1304 may be performed via cloud computing.

In some embodiments, substantially concurrently with performing act 1304, the influx management envelope engine may determine a dynamic pressure profile for another drilling fluid having a different density. In some such embodiments, act 1302 and act 1304 may be performed in parallel (e.g., but with drilling fluids having different densities and/or for different wellbore conditions).

Responsive to determining the post influx surface pressure, the method 1300 further includes determining whether the post influx surface pressures determining during act 1304 exceeds pressure thresholds, as shown in act 1306. For example, act 1306 may include determining whether the post influx surface pressure causes any of the wellbore equipment, the earth formation, or the operator margins to exceed pressure thresholds. By way of non-limiting example, act 1306 may include determining, for each post influx surface pressure, whether any of the wellbore equipment (e.g., the casing shoe, managed pressure drilling equipment, the rotary table (e.g., rotary table 220 (FIG. 2)), the earth formation (e.g., the pore pressure, the fracture pressure), or the operator margins (e.g., operator or company guidelines for threshold pressures or margins between operating pressures and maximum pressures) are exceeded for the given influx volume.

With continued reference to FIG. 13, the method 1300 may further include, for each post influx surface pressure, determining whether the drilling operation may continue with normal circulation of the drilling fluid, whether the managed pressure drilling equipment may continue to be used, or whether secondary well control equipment should be utilized to mitigate the influx volume, as shown in act 1308. In some embodiments, act 1308 includes determining whether the drilling fluid density should be changed (e.g., increased, decreased) to mitigate the influx volume. By determining whether the drilling operation may continue with normal circulation of the drilling fluid, whether the managed pressure drilling equipment may continue to be used, or whether secondary well control equipment should be utilized for each post influx surface pressure, act 1038 includes determining and defining boundaries of the influx management window.

The method 1300 may further include performing one or more of acts 1302 through 1308 for another drilling fluid having a different density, as shown in act 1310.

With continued reference to FIG. 13, the method 1300 may further include displaying the influx management envelope to a user, such as on a client device, as shown in act 1312. In some embodiments, act 1312 includes receiving the data from a remote locations and displaying the influx management envelope. In some embodiments, the influx management envelope is displayed graphically.

Performing at least a portion of the method 1300 via a simulation cluster remotely, such as via cloud computing, facilitates performing one or more acts of the method 1300 in parallel, significantly improved the processing speed and the speed at which an operator may receive the influx management window for planning of the wellbore. Accordingly, the methods described herein may facilitate improved and faster planning of wellbores and may more accurately predict wellbore conditions and mitigation activities during kick events.

FIG. 14 is a simplified flow diagram illustrating a method 1400 of generating an influx management envelope, according to at least one embodiment of the disclosure. The method 1400 includes, using a dynamic pressure model of a simulation cluster, for a drilling fluid density and each of a plurality of choke pressures, generating an output including a dynamic pressure profile of an annular pressure of the drilling fluid throughout the wellbore at 1402. For each output, and using a multiphase transient model of the simulation cluster, the method 1400 includes determining a post influx surface pressure for each of a plurality of influx volumes at 1404.

FIG. 15 is a simplified flow diagram illustrating a method 1500 of generating an influx management envelope, according to at least one embodiment of the present disclosure. The method 1500 includes, for a first influx volume, determining transient temperatures and pressures along a wellbore and a composition of the first influx volume for each of a plurality of sets of wellbore parameters using an equation of state transient multiphase model in a simulation cluster at 1502. The method 1500 further includes determining a post influx surface pressure as a result of the first influx volume for each of the plurality of sets of wellbore parameters at 1504. For a second influx volume and each of the plurality of sets of wellbore parameters, the method 1500 includes determining in parallel using the equation of state transient multiphase model in the simulation cluster, a post influx surface pressure as a result of the second influx volume at each of the plurality of sets of wellbore parameters at 1506.

One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.

The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.