METHOD OF USING A MAGNETIC ARRAY TO STRENGTHEN/DIRECT MAGNETIC FLUX IN A DOWNHOLE FLOW CONTROL VALVE COUPLER AND POWER GENERATOR

A magnetic coupling mechanism in a downhole flow control tool comprising a first chamber within a flow path of wellbore fluids with a first component comprising a Halbach array of magnets. A second chamber isolated from the wellbore environment comprises a second component with a Halbach array of magnets. The first chamber and the second chamber are coupled with a nonmagnetic separation. The second component is translated with the first component by a strong magnetic flux produced by the array of magnets.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

BACKGROUND

Hydrocarbons, such as oil and gas, are commonly obtained from subterranean formations that may be located onshore or offshore. The construction of a hydrocarbon producing well can comprise a number of different steps. Typically, the construction begins with drilling a wellbore at a desired wellsite, treating the wellbore to optimize production of hydrocarbons, and installing completion equipment to produce the hydrocarbons from the subterranean formation. During production of the formation fluid, formation sand may be swept into the flow path. The formation sand tends to be relatively fine sand that can erode production components in the flow path.

When formation sand is expected to be encountered in formation fluid, a lower completion assembly may be installed in the production zone between the formation and the production tubing comprising a plurality of sand screen assemblies. Each sand screen assembly generally includes a filter media, such as a sand screen, to filter fines from the formation fluid. The inflow of formation fluids can be balanced across the plurality of sand screen assembly inflow control devices (“ICDs”) that are configured to meter the inflow of formation fluids along the length of a lower completion assembly. Traditionally, ICDs are operated utilizing electric or hydraulic control lines extending from the surface, or through use of equipment lowered from the surface, or are otherwise autonomous in their operation, with no external control. An addressable ICD can utilize a power harvesting device to power a unit controller and one or more valves. The power harvesting device can utilize a turbine within a production flow passage to generate electric power. Fines within the production fluid may erode or foul the power harvesting device. A method of separating the power harvesting device from the erosive produced formation fluid is desirable.

DETAILED DESCRIPTION

As used herein, orientation terms “uphole,” “downhole,” “up,” and “down” are defined relative to the location of the earth's surface relative to the subterranean formation. “Down” and “downhole” are directed opposite of or away from the earth's surface, towards the subterranean formation. “Up” and “uphole” are directed in the direction of the earth's surface, away from the subterranean formation or a source of well fluid. “Fluidically coupled” means that two or more components have communicating internal passageways through which fluid, if present, can flow. A first component and a second component may be “fluidically coupled” via a third component located between the first component and the second component if the first component has internal passageway(s) that communicates with internal passageway(s) of the third component, and if the same internal passageway(s) of the third component communicates with internal passageway(s) of the second component.

Hydrocarbons, such as oil and gas, are produced or obtained from subterranean reservoir formations that may be located onshore or offshore. The development of subterranean operations and the processes involved in removing hydrocarbons from a subterranean formation typically involve a number of construction steps such as drilling a wellbore at a desired well site, isolating the wellbore with a barrier material, completing the wellbore with various production equipment, treating the wellbore to optimize production of hydrocarbons, and providing surface production equipment for the recovery of hydrocarbons from the wellhead.

During the completion operations, a completion string, for example, a packer and at least one sand screen, may be used to isolate a production zone when erosive sand particles are present or predicted within the fluids produced from the formation, e.g., production fluids. The completion operation can comprise an upper completion string and a lower completion string, also referred to as a lower completion assembly. Generally, a lower completion assembly comprises at least one sand screen comprising a base pipe with a flow passage and a filter media, e.g., sand screen, disposed around a portion of the base pipe. The filter media can be formed with a filtered flow area formed between the filter media and the base pipe. An adjustable electronic flow control node can be positioned along the base pipe and fluidically coupled to the filter media via the filter flow area. The adjustable electronic flow control node comprises a power harvesting device, a valve body, a flow control valve, and unit controller with a transceiver. The power harvesting device can be located within the flow passage between the filter media and valve body. A flow of production fluids through the flow passage can generate electrical power for the unit controller and flow control device. The unit controller can actuate the flow control device to position the flow control valve into a desired position within the valve body to meter the flow of production fluids from the flow passage and valve housing to an exit port. The transceiver can receive signals from the wellbore, e.g., electromagnetic signal or a pressure signal, comprising instructions for the position of the flow control valve.

In some embodiments, the electronic flow control nodes may be used to inject a working fluid into the wellbore annulus around the respective sand screen assembly. For example, a gravel pack slurry, acidizing treatment, hydraulic fracturing fluid or cake breaking fluid may be injected into the wellbore annulus.

In some embodiments, the lower completion can comprise two or more electronic flow control nodes configured to be operated in concert to achieve a particular objective. For example, the electronic flow control nodes may be sequentially opened and/or closed along the string.

In some embodiments, the power harvesting device can be divided into a clean side and a dirty side. The clean side of the power harvesting device can include a magnetic rotor coupled to a shaft of a generator. The dirty side of the power harvesting device can include a turbine with a magnetic hub, also referred to as a magnetic turbine. The magnetic flux between the magnetic rotor and the magnetic turbine can rotationally couple the magnetic rotor and the magnetic turbine. However, the torque capacity of the magnetic flux can limit the speed of the magnetic turbine.

A Halbach array can provide a solution to the limited toque capacity of the magnetic flux. A Halbach array is an orientation of magnetic poles of magnets into a pattern to increase the density of the magnetic flux. A plurality of magnets can be installed into the magnetic rotor and magnetic turbine arranged into a Halbach array with matching pole directions to increase the density of the magnetic flux and thus, increase the torque capacity of the magnetic flux.

Turning now toFIG.1, an exemplary environment100for a turbine assembly is illustrated. In some embodiments, wellsite environment100comprises a wellbore102extending from a surface location to a permeable subterranean formation110. The wellbore102can be drilled from surface location using any suitable drilling technique. The wellbore102can include a substantially vertical portion104that transitions to a deviated portion and into a substantially horizontal portion124. In some embodiments, the wellbore102may comprise a nonconventional, horizontal, deviated, multilateral, or any other type of wellbore. Wellbore102may be defined in part by a casing string106that may extend from a surface location to a selected downhole location. The casing string106may be isolated from the wellbore by cement108. Portions of wellbore102that do not comprise the casing string106may be referred to as open hole. Although the horizontal portion124is illustrated as an open hole section, it is understood that the horizontal section can include a casing string106and/or cement108. While the wellsite environment100illustrates a land-based subterranean environment, the present disclosure contemplates any wellsite environment including a subsea environment. In one or more embodiments, any one or more components or elements may be used with subterranean operations equipment located on offshore platforms, drill ships, semi-submersibles, drilling barges, and land-based rigs.

A production string112may be positioned within the wellbore102and extend from the surface location. The production string112can be any piping, tubular, or fluid conduit including, but not limited to, drill pipe, production tubing, casing, coiled tubing, and any combination thereof. The production string112provides a conduit for production fluids extracted from the formation110to travel to the surface. The production string112may additionally provide a conduit for fluids to be conveyed downhole and injected into the formation110, such as in an injection operation.

In some embodiments, the production string112can be releasably coupled to a lower completion114. For example, the production string112can mechanically and sealingly couple to the lower completion114by a completion assembly132, e.g., an anchor assembly. In some embodiments, the production string112can couple to the lower completion by a mechanical coupling132. The lower completion114can divide the production zone into various production intervals adjacent the formation110. The production zone can be the area within the wellbore102where various wellbore operations are to be undertaken using the lower completion114, such as production or injection operations.

As illustrated inFIG.1, the lower completion114includes an isolation packer126and a plurality of sand control screen assemblies116axially offset from each other along portions of the lower completion114. The isolation packer126can anchor and seal the lower completion114within the production zone. A zonal packer118can be placed between each screen assembly116to form a seal between the outer surface of the lower completion114and the inner surface of the wellbore102thereby defining corresponding production intervals. In operation, the screen assemblies116can filter particulate matter out of production fluid such that particulates and other fines are not produced to the surface and to prevent particulates from clogging portions of the lower completion114. Although the screen assemblies116are illustrated as being located in an open hole portion of the wellbore102, it is understood that one or more of the screen assemblies116can be arranged within cased portions of the wellbore102. Although a single screen assembly116is illustrated being located in each production interval, it is understood that 0, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of screen assemblies116may be located within a particular production interval. Although the lower completion114is illustrated with multiple production intervals separated by the zonal packers118, it is understood that the production zone may include 0, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or any number of production intervals with a corresponding number of zonal packers118used therein. Although the lower completion114is illustrated in a horizontal portion124of the wellbore102, it is understood that the lower completion114can be located in a vertical portion104, a deviated section, a multilateral section, or combinations thereof.

In some embodiments, the lower completion114can be used to undertake various wellbore operations. For example, the lower completion114can be used to extract production fluids120from the formation110and transport those fluids120to the surface via the production string112. The production fluids120can be water, oil, gas, acids, or any combination thereof.

In some embodiments, the lower completion114may be used to inject fluids122with various service operations into the surrounding subterranean formation110. For example, the lower completion114can be used with hydraulic fracturing operations, steam-assisted gravity drainage (SAGD) operations, wellbore treatment operations, gravel packing operations, acidizing operations, or any combination thereof. Accordingly, the injected fluids122may be water, fracturing fluids, steam, gas, aqueous or liquid chemicals, slurry, acids, or any combination thereof.

In some embodiments, the lower completion114comprises an adjustable electronic flow control node130, also referred to as an eICD130, located within each production interval. The eICD130can operate as a flow regulation devices, such as variable chokes and valves, to regulate the flow of the fluids120,122into and/or out of the lower completion114. The eICD130can receive signals from the surface via a transceiver and actuate the flow regulation devices accordingly as will be described further herein.

Turning now toFIG.2, a perspective view of an adjustable electronic flow control nodes can be described. In some embodiments, an eICD200, e.g., an adjustable electronic flow control node, can be an embodiment of the eICD130shown inFIG.1. The eICD200comprises a valve body202having a flow path204defined therethrough extending between a first fluid port206and a second fluid port208. A power harvesting device210may be disposed along the flow path204. Flow path204may be defined by one or more fluid channels or fluid ducts222formed in the valve body202, and may likewise include one or more flow chambers224fluidically coupling the channels222with the first fluid port206and the second fluid port208. In some embodiments, power harvesting device210is a turbine generator or blade generator that can be actuated by fluid flow along the flow path204. In other embodiments, power harvesting device210may be disposed to be actuated by fluid flow external of the valve body202, for example, production flow flowing past eICD200.

In some embodiments, production fluid can flow from the second fluid port208to the first fluid port206. In some embodiments, injection fluid can flow from the first fluid port206to the second fluid port208. The fluid flow from the first fluid port206to the second fluid port208, or vice-versa, can be metered by an adjustable valve212. The adjustable valve212can be a needle valve, a globe valve, a poppet valve, a gate valve, a ball valve or any suitable valve type. As illustrated inFIG.2, the adjustable valve212can be a needle valve comprising a stem230, a stem head226, and a valve seat228. A drive mechanism214can linearly position the stem head226relative to the valve seat228. The drive mechanism214can move the stem head226into a first position with full contact with the valve seat228to shut off the fluid flow within the flow chamber224, e.g., between the valve seat228and the first fluid port206. The drive mechanism214can move or position the stem head226away from, or distal to, the valve seat228to a second position to allow a maximum potential flow rate through the flow chamber224and through the flow path204. The drive mechanism214can position the stem head226in a third position, also referred to as a metering position, located between the first position and second position to reduce the flowrate of fluids within the flow path204to a desired flowrate.

In some embodiments, the adjustable valve212may establish a desired flowrate along the flow path204for different operations. For example, the adjustable valve212may positioned in the second position, e.g., fully open position, for fluid injection operations, such as acidizing, hydraulic fracturing, gravel packing and the like. In some embodiments, the adjustable valve212can establish a desired flow rate for production, e.g., fluid flow from the second fluid port208to the first fluid port206. In some scenarios, the adjustable valve212can be placed in the third position to meter the flowrate of production fluids through the flow path204.

In some embodiments, the drive mechanism214comprises a drive side magnet234, a wet side valve spool236, and an actuator. The actuator (not shown) can be an electric actuator coupled to the drive side magnet234. A unit controller216can be communicatively coupled to the actuator to provide power and instruction to establish a position of the drive side magnet234. The drive side magnet234can be magnetically coupled to the wet side valve spool236by a plurality of magnets. One or more sensors220can provide feedback to the unit controller216of the position of the actuator, the drive side magnet234, the stem head226, or combinations thereof. For example, the sensor220can be a positional sensor coupled to the actuator, the drive side magnet234, the stem head226, or combinations thereof. In another scenario, the sensor220can be a pressure sensor, a temperature sensor, a flow sensor to measure the environment within the flow chamber224. The unit controller216can receive a wireless signal from a transceiver218, for example, a pressure signal. The unit controller216can receive a signal and move the stem head226to a first position, a second position, or a third position in response to the signal with the sensor220providing feedback of the position. Although the sensor220is illustrated as a single sensor located within the flow chamber224, it is understood that the sensor220can be multiple sensors located anywhere within the valve body202and/or external to the valve body202. Although the transceiver218is described as receiving wireless signals, it is understood that the transceiver218can transmit wireless signals.

Turning now toFIG.3A, a top view of an exemplary turbine can be described. In some embodiments, a turbine assembly300of the power harvesting device210may be configured to receive a flow of a fluid312from a flow path204(shown inFIG.2) and convert the kinetic energy and potential energy of the fluid312into rotational motion and torque. The flow of the fluid312can be any type of fluid within the flow path204, for example, injection fluids and/or production fluids. The turbine assembly300can include a turbine body314with a plurality of turbine blades316, a turbine hub318, and at least one hub magnet320. The turbine blades316can be distributed about the turbine hub318and configured to receive the fluid312. The turbine blades316can be blades, plates, fins, or any other suitable element configured to transform fluid motion into rotational motion. For example, the turbine hub318can be urged to rotate in response to the fluid312impinging on the turbine blades316. The turbine assembly300can be located in a first chamber or a turbine chamber326. An axle328can be coupled to the turbine hub318at a center axis point and located in a receiving port within the turbine chamber326. A plurality of hub magnets320can be mounted to or fixed within the turbine hub318. Although the turbine hub318is illustrated with six hub magnets320A-H, it is understood that the turbine hub318can comprise 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, or any number of hub magnets320. As illustrated inFIG.3, the fluid312in the turbine assembly300is perpendicular to the central axis324of the turbine body314. Although the turbine assembly300is illustrated as a cross-flow turbine, it is understood that the turbine assembly300can be any other type of turbine that is configured to generate rotational motion from fluid flow, for example, the fluid flow could be substantially parallel to the rotational axis or central axis324of the rotor.

Turning now toFIG.3B, a schematic diagram illustrating an exemplary power harvesting device330can be described. In some embodiments, the power harvesting device330comprises the turbine assembly300and a generator332. The generator332comprises a stator334, a rotor336, a rotor coupling338, and a power unit340within a housing342. The generator332can operate in a sealed chamber344, also referred to as the second chamber, within the housing342. The generator332can produce electrical power346when the rotor336is rotating within the stator334. A power unit340comprises a rectifier circuit350and a power storage device352to condition and/or store the electrical power346. The stator334can comprise a plurality of windings322mounted on a core. The rotor336can comprise a plurality of magnets354mounted about a rotor axle358. A rotor coupling plate360can be a generally disk shape with a plurality of plate magnets362mount to or fixed with the rotor coupling plate360. The rotor coupling plate360can be rotationally coupled to the rotor336by the rotor axle358. The rotor coupling plate360can be magnetically coupled to the turbine assembly300. The turbine assembly300can be located in the turbine chamber326also referred to as the first chamber. For example, a plurality of magnetic flux366can extend across a non-magnetic cap368from the plurality of plate magnets362to the plurality of hub magnets320.

During operation, a flowrate of fluid within the flow path204can induce rotational motion of the turbine assembly300. The plurality of magnetic flux366can rotationally couple the turbine assembly300to the rotor coupling plate360, thus the rotational motion of the turbine assembly300can rotate the rotor336within the stator334to generate electrical power346. The power unit340may store and deliver a steady power supply for consumption by a load, for example, the unit controller216.

In an embodiment, the turbine assembly300and drive mechanism214may utilize a magnetic field generated by a Halbach Array to generate a plurality of magnetic fluxes366with the rotor coupling plate360. In general, a Halbach Array comprises an arrangement of permanent magnets that augments the magnetic field on one side of the array while cancelling the field to near zero on the other side. The arrangement can comprise a spatially rotating pattern of magnetization. Halbach Arrays may be implemented in a variety of shapes such as array (bar or rod magnets), sheets, plates, and cylinders (e.g., in the form of Halbach Cylinders). When the Halbach Array is used with a cylindrical arrangement, the magnetic field may be augmented either inside or outside the cylinder, with a corresponding decrease in the magnetic field on the opposite side-either outside or inside the cylinder, respectively.

Generally, the magnets may be made from a material that is magnetized and creates its own persistent magnetic field. In an embodiment, the magnets of the turbine assembly300and drive mechanism214may be permanent magnets formed, at least in part, from one or more ferromagnetic materials. Suitable ferromagnetic materials useful with the magnets described herein may include, but are not limited to, iron, cobalt, rare-earth metal alloys, ceramic magnets, alnico nickel-iron alloys, rare-earth magnets (e.g., a Neodymium magnet and/or a Samarium-cobalt magnet). Various materials useful with the magnets of the turbine assembly300and drive mechanism214may include those known as Co-netic AAR, Mumetal®, Hipernon®, Hy-Mu-80®, Permalloy®, each of which comprises about 80% nickel, 15% iron, with the balance being copper, molybdenum, and/or chromium.

Turning now toFIG.4, an exemplary Halbach Array400comprising a plurality of magnets402may be arranged in a rotating pattern (in this case right, down, left, up, where “up” indicates north). The exemplary Halbach array400may be utilized in the drive mechanism214as that236and/or that234. The rotating pattern of the permanent magnets402augments the magnetic field410on a first side406relative to the decreased field408on the second side404. The degree of augmentation and/or cancellation of the decreased field408,410on each side of the permanent magnets402may vary depending on various considerations such as the relative strength of the magnets and/or the alignment and orientation of the magnets. In an embodiment, the augmented magnetic field410is greater than the decreased field408. In some embodiments, the ratio of the magnetic field strength of the decreased field408at a given distance from the magnets to the magnetic field strength of the augmented field410at the distance from the magnets on an opposite side of the magnets402may be in the range of from about 1:1000 to about 1:1.5, from about 1:100 to about 1:2, or from about 1:90 to about 1:4. The augmented field410of the Halbach Array can increase the amount of torque transfers to the generator332and the amount of linear force transferred to the adjust valve230.

Turning now toFIG.5A, a top view illustrating an exemplary turbine body with a magnetic coupling can be described. In some embodiments, the exemplary turbine body500comprises a turbine hub318, a plurality of blades316, an axle328, and Halbach array of wedge magnets504. The wedge magnets504can be generally wedge or pie shaped magnets with a pole or flux oriented in the direction indicated. For example, magnet504A can be oriented left, magnet504B can be oriented up, magnet504C can be oriented right, magnet504D can be oriented down, magnet504E can be oriented left, magnet504F can be oriented up, magnet504G can be oriented right, and magnet504H can be oriented down. The rotating pattern of the permanent magnets504can augment the magnetic field on a first side508. In some embodiments, a rotor coupling plate, e.g., plate360, comprises a Halbach array of wedge magnets configured establish a plurality of augmented flux, e.g., flux366, with the turbine body500. The augment flux of the Halbach array between the turbine body500and the rotor coupling plate can increase the torque capacity of the generator332and increase the potential power output of the power harvesting device330.

Turning now toFIG.5B, a top view illustrating an exemplary turbine body with an enhance magnetic coupling can be described. In some embodiments, the exemplary turbine body520comprises a turbine hub318, a plurality of blades316, an axle328, and Halbach array of narrow wedge magnets524. The narrow wedge magnets524can be generally wedge or pie shaped magnets with a pole or flux oriented in the direction indicated. For example, magnet524A can be oriented left, magnet524B can be oriented up, magnet524C can be oriented right, magnet524D can be oriented down, magnet524E can be oriented left, magnet524F can be oriented up, magnet524G can be oriented right, magnet524H can be oriented down, magnet524I can be oriented left, magnet524J can be oriented up, magnet524K can be oriented right, magnet524L can be oriented down, magnet524M can be oriented left, magnet524N can be oriented up, magnet524O can be oriented right, and magnet524P can be oriented down. The rotating pattern of the permanent magnets524can augment the magnetic field on a first side528. In some embodiments, a rotor coupling plate, e.g., plate360, comprises a Halbach array of wedge magnets configured establish a plurality of augmented flux, e.g., flux366, with the turbine body520. The augment flux of the Halbach array between the turbine body520and the rotor coupling plate can increase the torque capacity of the generator332and increase the potential power output of the power harvesting device330.

Turning now toFIG.6, a perspective view of a drive mechanism with a Halbach array can be described. In some embodiments, a drive mechanism600comprises a drive side magnet602, a wet side valve spool604, and an actuator606. The actuator606can be an electric actuator coupled to the drive side magnet602. A unit controller216can be communicatively coupled to the actuator606to provide power and instruction to establish a position of the drive side magnet602. The drive side magnet602comprises a Halbach array of a plurality of magnets610arranged in a rotating pattern. The exemplary Halbach array can comprise magnets610with the orientation of up, left, down, right, up, left, down, right, up, and left. The rotating array of magnets610can establish an augmented, or strong side flux612oriented towards the wet side spool604and a decreased side, or weak side flux614, oriented away from the wet side spool604. The wet side spool604comprises a Halbach array of a plurality of magnets620arranged in a pattern of down, right, up, left, down, right, up, left, down, and right. The rotating array of magnets620can establish an augmented, or strong side flux622oriented towards the drive side magnet602and a decreased side, or weak side flux624, oriented away from the drive side magnet602. The drive side magnet234can be magnetically coupled to the wet side valve spool236through a non-magnetic wall633by with an augmented or strong side flux612,622.

The drive side magnet602, the actuator606, and the unit controller216can be located in a positioning chamber630within the valve body202. The positioning chamber630, also referred to as the second chamber, can be sealed and isolated from the wellbore environment. The wet side spool604and the valve212can be located within the flow chamber224, also referred to as the first chamber, of the valve body202. In a scenario, production fluid can exit the valve seat228into the flow chamber224and exit the first fluid port206. The valve212can be positioned by the wet side spool604located within the flow chamber224to a first position, a second position, or a third position, e.g., a fully closed position, a fully open position, or a metered position.

Turning now toFIG.7, a computer system700suitable for implementing one or more embodiments of the unit controller, for example, unit controller216, including without limitation any aspect of the computing system associated with the valve operation ofFIG.2andFIG.6. The computer system700includes one or more processors702(which may be referred to as a central processor unit or CPU) that is in communication with memory704, secondary storage706, input output devices710, and network devices. The computer system700may continuously monitor the state of the input devices and change the state of the output devices based on a plurality of programmed instructions. The programming instructions may comprise one or more applications retrieved from memory704for executing by the processor702in non-transitory memory within memory704. The input output devices may comprise a Human Machine Interface with a display screen and the ability to receive conventional inputs from the service personnel such as push button, touch screen, keyboard, mouse, or any other such device or element that a service personnel may utilize to input a command to the computer system700. The secondary storage706may comprise a solid state memory, a hard drive, or any other type of memory suitable for data storage. The secondary storage706may comprise removable memory storage devices such as solid state memory or removable memory media such as magnetic media and optical media, i.e., CD disks. The computer system700can communicate with various networks with the network devices714comprising wired networks, e.g., Ethernet or fiber optic communication, and short range wireless networks such as Wi-Fi (i.e., IEEE 802.11), Bluetooth, or other low power wireless signals such as ZigBee, Z-Wave, 6LoWPan, Thread, and WiFi-ah. The computer system700may include a transceiver218for communicating wirelessly.

In some embodiments, the computer system700may comprise a DAQ card716for communication with one or more sensors. The DAQ card716may be a standalone system with a microprocessor, memory, and one or more applications executing in memory. The DAQ card716may be a card or a device within the computer system700. In some embodiments, the DAQ card716may be combined with the input output device710. The DAQ card716may receive one or more analog inputs, one or more frequency inputs, and one or more Modbus inputs. For example, the analog input may include a positional sensor, e.g., a linear sensor. For example, the frequency input may include a flow meter, i.e., a fluid system flowrate sensor. For example, the Modbus input may include a pressure transducer. The DAQ card716may convert the signals received via the analog input, the frequency input, and the Modbus input into the corresponding sensor data. For example, the DAQ card716may convert a frequency input from the flowrate sensor into flowrate data measured in gallons per minute (GPM).

Additional Disclosure

The following are non-limiting, specific embodiments in accordance and with the present disclosure:

A first embodiment, which is a magnetic coupling mechanism in a downhole flow control tool, comprising a first chamber configured to receive i) production fluids or ii) injection fluids; a first component with a plurality of magnets located within the first chamber, and wherein the plurality of magnets are configured in a Halbach Array; a second chamber configured to exclude a wellbore environment; a second component with a plurality of magnets located within the second chamber, and wherein the plurality of magnets are configured in a Halbach Array; wherein the first chamber and the second chamber share a non-magnetic separation; and wherein the first component is magnetically coupled to the second component by a plurality of strong magnetic flux.

A second embodiment, which is the magnetic coupling mechanism of the first embodiment, wherein the plurality of magnets in the first component are configured to produce a weak magnetic flux directed away from the non-magnetic separation and a strong magnetic flux directed towards the non-magnetic separation.

A third embodiment, which is the magnetic coupling mechanism of any of the first and the second embodiments, wherein the plurality of magnets in the second component are configured to produce a weak magnetic flux directed away from the non-magnetic separation and a strong magnetic flux directed towards the non-magnetic separation.

A fourth embodiment, which is the magnetic coupling mechanism of any of the first through the third embodiments, wherein the first component is configured to axially translate; and wherein the second component is biased to axially translate by the plurality of strong magnetic flux.

A fifth embodiment, which is the magnetic coupling mechanism of the first through the fourth embodiments, wherein the first component is configured to rotationally translate; and wherein the second component is biased to rotationally translate by the plurality of strong magnetic flux.

A sixth embodiment, which is the magnetic coupling mechanism of any of the first through the fifth embodiments, wherein the first component and the second component are separated by the non-magnetic separation.

A seventh embodiment, which is the magnetic coupling mechanism of any of the first through the sixth embodiment, wherein the downhole flow control tool comprises a valve body with a flow path, an energy harvesting device, an adjustable valve, and a unit controller.

An eighth embodiment, which is the magnetic coupling mechanism of any of the first through the seventh embodiments, wherein the flow path comprises a first fluid port within a fluid chamber fluidically coupled to a second fluid port via at least one fluid duct; wherein the energy harvesting device comprises a generator and a turbine assembly; wherein the turbine assembly is fluidically coupled to the flow path and located between the second fluid port and the fluid chamber; and wherein the turbine assembly is configured to induce rotation within the generator.

A ninth embodiment, which is the magnetic coupling mechanism of any of the first through the eighth embodiments, wherein the first component and the second component are located within the energy harvesting device.

A tenth embodiment, which is the magnetic coupling mechanism of any of the first through the ninth embodiments, wherein the adjustable valve comprises a drive mechanism and a stem head; wherein the drive mechanism is communicatively coupled to the unit controller; wherein the stem head is located within a fluid chamber; and wherein the drive mechanism is configured to position the stem head in i) a first position, ii) a second position, or iii) a third position.

An eleventh embodiment, which is magnetic coupling seal mechanism of any of the first through the tenth embodiments, wherein the first component and the second component are located within the adjustable valve.

A twelfth embodiment, which a method of actuating a downhole mechanism by a magnetic coupling within a downhole tool assembly, comprising positioning a first component in a first chamber, wherein the first component comprises a plurality of magnets, wherein the plurality of magnets are configured to produce a strong magnetic flux on a first side; positioning a second component into a second chamber, wherein the second component comprises a plurality of magnets, wherein the plurality of magnets are configured to produce a strong magnetic flux on a second side; wherein the first chamber and the second chamber are coupled by a non-magnetic separation; wherein the first side of the first component is oriented towards the non-magnetic separation; wherein the second side of the second component is oriented towards the non-magnetic separation; magnetically coupling the strong magnetic flux on the first side of the first component to the strong magnetic flux on the second side of the second component; and actuating the second component with the first component.

A thirteenth embodiment, which is the method of the twelfth embodiment, wherein the first chamber comprises a flow path for wellbore fluids; and wherein the second chamber excludes a wellbore environment.

A fourteenth embodiment, which is the method of the thirteenth embodiment, further comprising rotating the first component with a flowrate of wellbore fluids; and generating electrical power within the second chamber in response to a rotational motion of the second component.

A fifteenth embodiment, which is the method of any of the thirteenth through the fourteenth embodiment, wherein the first chamber excludes the wellbore environment; and wherein the second chamber comprises a flow path for wellbore fluids.

A sixteenth embodiment, which is the method of any of the thirteenth through the fifteenth embodiment, further comprising positioning a first component with an actuator into i) a first position, ii) a second position, or iii) a third position; and changing a flowrate of wellbore fluids within the flow path with a second component in response to the position of the first component.

A seventeenth embodiment, which is the method of any of the thirteenth through the fifteenth embodiment, wherein the wellbore fluids are i) production fluids or ii) injection fluids.

An eighteenth embodiment, which is a downhole flow control tool system, comprising a first component in a first chamber, wherein the first component comprises a plurality of magnets, wherein the plurality of magnets are configured to produce a strong magnetic flux on a first side; a second component in a second chamber, wherein the second component comprises a plurality of magnets, wherein the plurality of magnets are configured to produce a strong magnetic flux on a second side, and wherein the first chamber and the second chamber are coupled by a non-magnetic separation; a magnetic coupling by the strong magnetic flux on the first side of the first component and the strong magnetic flux on the second side of the second component; and wherein the magnetic coupling is configured to: actuating the second component with the first component.

A nineteenth embodiment, which is the downhole flow control tool system of the eighteenth embodiment, wherein actuating the second component with the first component further comprises: rotating the first component within a flow path with a flowrate of wellbore fluids; and generating electrical power within the second chamber that excludes a wellbore environment in response to a rotational motion of the second component.

A twentieth embodiment, which is the downhole flow control tool system of the eighteenth or nineteenth embodiment, wherein actuating the second component with the first component further comprises: positioning a first component with an actuator into i) a first position, ii) a second position, or iii) a third position, wherein the first chamber excludes a wellbore environment; and changing a flowrate of wellbore fluids within a flow path with a second component in response to the position of the first component.