WO2025226490A1

WO2025226490A1 - Method of measuring the composition of production fluid flowing through an icd

Info

Publication number: WO2025226490A1
Application number: PCT/US2025/024922
Authority: WO
Inventors: Ryan W. Mcchesney; Gordon Mcleary; Gregory T. Werkheiser; Georgina Corona CORTES
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2024-04-23
Filing date: 2025-04-16
Publication date: 2025-10-30
Anticipated expiration: 2026-10-23
Also published as: US20250327378A1

Abstract

Disclosed herein are systems and methods of controlling downhole production flow from one or more production zones of a well. A system may include at least one downhole power generator, at least one sensor, at least one electronic assembly, and at least one production valve. In some systems, the downhole power generator, the sensor, the electronic assembly, and the production valve are incorporated within the same module. The downhole power generator is fluidically connected to the fluid inside the production tubing string. The sensor is electrically connected to the downhole power generator, wherein the sensor measures a phase of the fluid. The electronic assembly is connected to the downhole power generator and the sensor. The production valve is electrically connected to the electronic assembly and fluidly connected to the fluid inside the production tubing string.

Description

METHOD OF MEASURING THE COMPOSITION OF PRODUCTION FEUID

FLOWING THROUGH AN ICD

BACKGROUND

[0001] Hydrocarbon production wells may start to produce water and/or gases through coning as the oil-bearing layer is produced. It may be desirable to choke back flow from that zone when coning happens and to minimize water production by the zone while maximizing oil production without depleting the reservoir pressure. Further, sand production may be minimized, and production zones may be balanced.

[0002] Therefore, it will be appreciated that advancements in the art of variably restricting fluid flow in a well would be desirable in the circumstances mentioned above, and such advancements would also be beneficial in a wide variety of other circumstances.

BRIEF DESCRIPTION OF THE DRAWINGS

[0003] These drawings illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the disclosure.

[0004] FIG. 1 shows a schematic view of a well system including a variable flow resistance system in accordance with one or more embodiments of the present disclosure;

[0005] FIG. 2 shows a schematic view of a variable flow resistance system in accordance with one or more embodiments of the present disclosure;

[0006] FIG. 3 shows a detailed view of a variable flow resistance system in accordance with one or more embodiments of the present disclosure;

[0007] FIG. 4 shows a schematic view of a variable flow resistance system in accordance with one or more embodiments of the present disclosure;

[0008] FIG. 5 shows a schematic view of a variable flow resistance system in accordance with one or more embodiments of the present disclosure;

[0009] FIG. 6 shows a schematic view of a variable flow resistance system in accordance with one or more embodiments of the present disclosure;

[0010] FIG. 7 shows a schematic view of a variable flow resistance system in accordance with one or more embodiments of the present disclosure;

[0011] FIG. 8 shows a schematic view of a variable flow resistance system in accordance with one or more embodiments of the present disclosure;

[0012] FIG. 9 shows a flowchart of a method of variably controlling flow resistance in a well in accordance with one or more embodiments of the present disclosure; [0013] FIG. 10 shows a schematic view of a gamma ray multiphase flow meter in accordance with one or more embodiments of the present disclosure;

[0014] FIG. 11A shows a schematic view of the electrode on the outside of a tubing in accordance with one or more embodiments of the present disclosure;

[0015] FIG. 1 IB shows a schematic view of a cross section of a tubing with water and air inside the tubing, the tubing or pipe, and the electrode on the outside in accordance with one or more embodiments of the present disclosure;

[0016] FIG. 11C shows a schematic view of the electronic system in accordance with one or more embodiments of the present disclosure;

[0017] FIG. 12 shows a schematic view of a magnetic inductive flow meter in accordance with one or more embodiments of the present disclosure;

[0018] FIG. 13 shows a schematic view of a magnetic resonance flow meter in accordance with one or more embodiments of the present disclosure;

[0019] FIG. 14 shows a schematic view of an ultrasonic flow meter in accordance with one or more embodiments of the present disclosure; and

[0020] FIG. 15 shows a schematic view of a variable flow resistance system in accordance with one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

[0021] The present disclosure relates to systems and methods of controlling downhole production flow from one or more production zones of a well using at least one downhole pow er generator, at least one sensor, at least one electronic assembly, and at least one production valve. In embodiments, the downhole power generator, the sensor, the electronic assembly, and the production valve are physically separated. In other embodiments, they are incorporated within the same system or module. In embodiments, the electronic assembly communicates wirelessly to surface to update the operator with the information from the power generation system and/or the sensor.

[0022] In some embodiments, the downhole power generator may be any variable flow resistance system, turbine, or rotor capable of generating pow er in contact with a downhole fluid such as a water turbine generator, a gas turbine generator, or any turbine capable of generating electricity when fluidically connected to any flowing fluid such as water and/or hydrocarbon, for example. In embodiments, the downhole power generator is electrically connected to one or more sensors. [0023] In embodiments, the sensor may be any sensor capable of monitoring the oil-water ratio, the gas-oil ratio, the gas-water ratio, the chemical composition of the fluid in the production tubing, at least one physical property of the fluid, or any combination thereof. The sensor may be any sensor capable of measuring at least one physical property characteristic of the phase of the fluid or its chemical composition such as an optical sensor, a nuclear magnetic resonance spectrometer, a gas chromatography mass spectrometer, a resistivity sensor, an impedance sensor, an electromagnetic sensor, an acoustic sensor, a density sensor, a viscosity sensor, a pressure sensor, a temperature sensor, or any combination thereof, for example. In one or more embodiments, the sensor may be coupled with a flow meter such as a gamma ray multiphase flow meter, a capacitive flow meter, a magnetic inductive flow meter, a resonance flow meter, an ultrasonic flow meter, for example.

[0024] In embodiments, the power generator may be used as sensor to measure at least one physical property of the fluid such as viscosity or density, for example. More specifically, as the power generated by the turbine and the number of rotations per minute of the turbine are recorded at the same time, at least one physical properties of the fluid, such as viscosity' for example, may be calculated from these inputs. Similarly, at least one pressure transducer and/or at least one temperature transducer may be used to calculate at least one physical property of the fluid such as viscosity' or density, for example. Further, from the at least one physical property obtained from these measurements, the phase of the fluid may be confirmed. For example, the power output could be monitored as a function of inlet pressure to determine a fluid property. The phase of the fluid could be detected, but also the mixtures of oil and water or even gas. The nature of the mixture could also be identified as some mixtures emulsify while others do not yielding different properties.

[0025] In embodiments, tracers may be installed inside the production tubing that may be released inside the flow line upon contact with water and/or sand. This tracer may then be detected by one or more of the sensors discussed above. The tracer may be any chemicals or physical properties that can differentiate an oil phase from a water phase including any dye, ions, isotopes, fluoride, radioactive compounds, heat transport, for example. In some embodiments, tracers are released upon contact with sand including upon sand abrasion against the production tubing where the tracers had been installed, for example. In other embodiments, a water tracer is injected into the water reservoir. In embodiments, the water tracer is injected into a water injector well to understand reservoir connectivity', for example.

[0026] In one or more embodiments, the electronic assembly is autonomous and analyzes the information from the power generation system and/or the sensor and sends a command to close or open at least partially the production valve based on the information gathered. In embodiments, the electronic assembly communicates wirelessly to surface to update the operator with the information from the power generation system and/or the sensor. Further, the operator may send a command to override the electronic assembly decision.

[0027] In embodiments, the production valve may be any valve capable of controlling the flow within a tubing such as an inflow control device (ICD) or an interv al control valve (ICV). The inflow control device or interval control valve may be any device capable of controlling the flow of the fluid transported inside a production tubing such as the Halliburton's EquiFlow® inflow control device (ICD) or autonomous inflow control device (AICD), for example. An active flow control device via a gate valve, ball valve, barrel valve, or any other valve could be used, for example. The valve may be manipulated using electric motors, hydraulics, magnetic fields, or any other means.

[0028] Turning now to the figures, FIG. 1 shows a well system 10 that can embody principles of the present disclosure. As depicted in FIG. 1, a wellbore 12 has a generally vertical uncased section 14 extending downwardly from casing 16. as well as a generally horizontal uncased section 18 extending through an earth formation 20.

[0029] A tubular string 22 (such as a production tubing string) is installed in the wellbore 12. Interconnected in the tubular string 22 are multiple well screens 24, variable flow resistance systems 25, and packers 26. The packers 26 seal off an annulus 28 formed radially between the tubular string 22 and the horizontal uncased section 18. In this manner, fluids 30 may be produced from multiple intervals or zones of the formation 20 via isolated portions of the annulus 28 between adjacent pairs of the packers 26.

[0030] Positioned between each adjacent pair of the packers 26, a well screen 24 and a variable flow resistance system 25 are interconnected in the tubular string 22. The well screen 24 filters the fluids 30 flowing into the tubular string 22 from the annulus 28. The variable flow resistance system 25 variably restricts flow of the fluids 30 into the tubular string 22, based on certain characteristics of the fluids.

[0031] At this point, it should be noted that the well system 10 is illustrated in the drawings and is described herein as merely one example of a wide variety of well systems in which the principles of this disclosure can be utilized. It should be clearly understood that the principles of this disclosure are not limited at all to any of the details of the well system 10, or components thereof, depicted in the drawings or described herein.

[0032] For example, it is not necessary in keeping with the principles of this disclosure for the wellbore 12 to include a generally vertical uncased section 14 or a generally horizontal uncased section 18, as a wellbore section may be oriented in any direction, and may be cased or uncased, without departing from the scope of the present disclosure. It is not necessary for fluids 30 to be only produced from the formation 20 as, in other examples, fluids could be injected into a formation, such as injected through the tubular string 22 and out into the formation 20, or fluids could be both injected into and produced from a formation, etc. Further, it is not necessary for one each of the well screen 24 and variable flow resistance system 25 to be positioned between each adjacent pair of the packers 26. It is not necessary for a single variable flow resistance system 25 to be used in conjunction with a single well screen 24. Any number, arrangement and/or combination of these components may be used.

[0033] It is not necessary' for any variable flow resistance system 25 to be used with a well screen 24. For example, in injection operations, the injected fluid could be flowed through a variable flow resistance system 25, without also flowing through a well screen 24.

[0034] It is not necessary for the well screens 24, variable flow resistance systems 25, packers 26 or any other components of the tubular string 22 to be positioned in vertical uncased section 14 and horizontal uncased section 18 of the wellbore 12. Any section of the wellbore 12 may be cased or uncased, and any portion of the tubular string 22 may be positioned in an uncased or cased section of the wellbore, in keeping with the principles of this disclosure.

[0035] It should be clearly understood, therefore, that this disclosure describes how to make and use certain examples, but the principles of the disclosure are not limited to any details of those examples. Instead, those principles can be applied to a variety’ of other examples using the knowledge obtained from this disclosure.

[0036] It will be appreciated by those skilled in the art that it would be beneficial to be able to regulate flow of the fluids 30 into the tubular string 22 from each zone of the formation 20, for example, to prevent water coning 32 or gas coning 34 in the formation. Other uses for flow regulation in a well include, but are not limited to, balancing production from (or injection into) multiple zones, minimizing production or injection of undesired fluids, maximizing production or injection of desired fluids, etc.

[0037] Examples of a variable flow resistance systems 25 described more fully below can provide these benefits by increasing resistance to flow if a fluid velocity increases beyond a selected level (e.g., to thereby balance flow among zones, prevent water or gas coning, etc.), or increasing resistance to flow if a fluid viscosity decreases below a selected level (e.g., to thereby restrict flow of an undesired fluid, such as water or gas, in an oil producing well).

[0038] Whether a fluid is a desired or an undesired fluid depends on the purpose of the production or injection operation being conducted. For example, if it is desired to produce oil from a well, but not to produce water or gas, then oil is a desired fluid and, water and gas are undesired fluids.

[0039] Note that, at downhole temperatures and pressures, hydrocarbon gas can actually be completely or partially in liquid phase. Thus, it should be understood that when the term “gas” is used herein, supercritical, liquid, and/or gaseous phases are included within the scope of that term.

[0040] Referring now to FIG. 2, a schematic view of a variable flow resistance system 25 in accordance with one or more embodiments of the present disclosure is shown. The variable flow resistance system 25 may include a sensor 42, an actuator 44, an electronic assembly 46, and a power generator 48. In this example, a fluid 36 (which can include one or more fluids, such as oil and water, liquid water and steam, oil and gas, gas and water, oil, water and gas, etc.) may be filtered by well screen 24 (referring to FIG. 1), and may then flow into a first flow path 38 (e.g., an inlet flow path) of the variable flow resistance system 25. A fluid can include one or more undesired or desired fluids. Both steam and water can be combined in a fluid. As another example, oil, water, and/or gas can be combined in a fluid. Flow of the fluid 36 through the variable flow resistance system 25 is resisted to control a flow rate of the fluid flowing through variable flow resistance system 25. The fluid 36 may then be discharged from the variable flow resistance system 25, such as to an interior or exterior of the tubular string 22 (referring to FIG. 1) via a second flow path 40 (e.g., an outlet flow path). As used herein, the first flow path 38 and the second flow path 40 may be generally described and function as an inlet flow path and an outlet flow path, respectively. However, the present disclosure is not so limited, as the flow of the fluid 36 may be reversed, such as during injection applications, through variable flow resistance system 25 such that the first flow path 38 and the second flow path 40 may be generally described and function as an outlet flow path and an inlet flow path, respectively.

[0041] In other examples, well screen 24 (referring to FIG. 1) may not be used in conjunction with variable flow resistance system 25 (e.g., in injection operations), the fluid 36 could flow in an opposite direction through the various elements of the well system 10 (referring to FIG. 1) (e.g., in injection operations), a single variable flow resistance system 25 could be used in conjunction with multiple well screens, multiple variable flow resistance systems could be used with one or more well screens, the fluid could be received from or discharged into regions of a well other than an annulus or a tubular string, the fluid could flow through the variable flow resistance system 25 prior to flowing through well screen 24, any other components could be interconnected upstream or downstream of well screen 24 and/or variable flow resistance system 25. etc. Thus, it will be appreciated that the principles of this disclosure are not limited at all to the details of the example depicted in the figures and described herein. Further, additional components (such as shrouds, shunt tubes, lines, instrumentation, sensors, inflow control devices, etc.) may also be used in accordance with the present disclosure, if desired.

[0042] The variable flow resistance system 25 is depicted in simplified form in FIG. 2, but in a preferred example, variable flow resistance system 25 may include various passages and devices for performing various functions, as described more fully below. In addition, variable flow resistance system 25 at least partially extends circumferentially about tubular string 22 (referring to FIG. 1), or variable flow resistance system 25 may be formed in a wall of a tubular structure interconnected as part of the tubular string.

[0043] In other examples, variable flow resistance system 25 may not extend circumferentially about a tubular string or be formed in a wall of a tubular structure. For example, variable flow resistance system 25 could be formed in a flat structure, etc. Variable flow resistance system 25 could be in a separate housing that is attached to tubular string 22 (referring to FIG. 1), or it could be oriented so that the axis of second flow path 40 is parallel to the axis of tubular string 22. Variable flow resistance system 25 could be on a logging string, production string, drilling string, coiled tubing, or other tubular string or attached to a device that is not tubular in shape. Any orientation or configuration of variable flow resistance system 25 may be used in keeping with the principles of this disclosure.

[0044] Referring now back to FIG. 2, variable flow resistance system 25 includes the first flow path 38 to receive fluid into variable flow resistance system 25 and a second flow path 40 to send fluid out of variable flow resistance system 25. When fluid exits variable flow resistance system 25, the fluid may, for example, enter into the interior of a tool body or out of the exterior of a tool body used in conjunction with the variable flow resistance system 25. The variable flow resistance system 25 may further include a sensor 42. an actuator 44, an electronic assembly 46, and a power generator 48. As described above, sensor 42 is included to measure one or more properties or characteristics of the fluid received into variable flow resistance system 25, such as measure the flow rate of the fluid received into variable flow resistance system 25. Though not so limited, and as discussed below, sensor 42 may be positioned near or within the first flow path 38 to measure the property or characteristic of the fluid received into variable flow resistance system 25 through the first flow path 38.

[0045] Actuator 44 may be any valve including any production valve controlling the flow within a tubing such as an inflow control device (ICD) or an interval control valve (ICV). Actuator 44 may control or adjust an inflow rate of fluid received into variable flow resistance system 25 and the first flow path 38. Additionally or alternatively, actuator 44 may control or adjust the restriction of fluid inflow received into variable flow resistance system 25 and the first flow⁷ path 38 and/or control or adjust a drop in pressure between first flow path 38 and second flow path 40. For example, actuator 44 may be positioned or included within variable flow resistance system 25 to extend into and retract from the fluid flow' path extending and formed through variable flow resistance system 25. To increase the inflow rate of the fluid, or decrease the inflow fluid restriction or pressure drop across variable flow⁷ resistance system 25, actuator 44 may retract to enable more fluid to flow through the fluid flow path of variable flow resistance system 25. To decrease the inflow⁷ rate of the fluid, or increase the inflow fluid restriction or pressure drop across variable flow⁷ resistance system 25, actuator 44 may extend to restrict the fluid flow⁷ through the fluid flow⁷ path of variable flow⁷ resistance system 25. Further, in one or more embodiments, actuator 44 may be used to fully stop or inhibit the fluid flow through the fluid flow path of variable flow resistance system 25. For example, if variable flow resistance system 25 is turned or powered off, actuator 44 may fully extend to prevent fluid flow through the fluid flow path of variable flow⁷ resistance system 25. Accordingly, actuator 44 may be used as or include an adjustable valve to be in a fully open position, a fully closed position, or an intermediate position to control the flow rate of fluid through variable flow resistance system 25. Further, in one or more embodiments, the control or adjustment of the inflow rate of fluid, the restriction of fluid inflow, or the pressure drop may all be parameters related to each other. Accordingly, as used herein, when referring to control or adjustment of one parameter, such as the inflow rate of fluid, may also be referring to control or adjustment of another parameter without departing from the scope of the present disclosure.

[0046] Actuator 44 may include a mechanical actuator (e.g., a screw assembly), an electrical actuator (e.g., piezoelectric actuator, electric motor), ahydraulic actuator (e.g., hydraulic cylinder and pump, hydraulic pump), a pneumatic actuator, and/or any other type of actuator known in the art. For example, actuator 44 may include a linear or axially driven actuator, in which actuator 44 interacts with an orifice included in the first flow⁷ path 38 to operate as an adjustable valve and control the inflow⁷ rate of the fluid.

[0047] Still referring to FIG. 2, variable flow⁷ resistance system 25 may include one or more power sources. For example, variable flow resistance system 25 may include a power generator 48 and/or a power storage device (not shown). Power generator 48 may be any downhole power generator described above. Power generator 48 may be used to generate pow er for variable flow resistance system 25, and the power storage device may be used to provide stored power for variable flow resistance system 25 and/or store power generated by power generator 48. In one embodiment, power generator 48 may include a turbine and may be able to generate power from fluid received into the first flow path 38 and flowing through variable flow resistance system 25. Power generator 48 may additionally or alternatively include other types of power generators, such as a flow induced vibration power generator and/or a piezoelectric generator, to generate power from the fluid received into variable flow resistance system 25 and/or from other energy sources present downhole (e.g., temperature and/or pressure sources).

[0048] The power storage device may be included within electronic assembly 46 for variable flow resistance system 25 and may be used to provide stored power. In one embodiment, the power storage device may be able to store power generated by power generator 48 and provide this stored power for variable flow resistance system 25. The power storage device may include a capacitor (e.g., super capacitor), battery (e.g., rechargeable battery), and/or any other type of power storage device known in the art. In one or more embodiments, sensor 42 and/or actuator 44 of variable flow resistance system 25 may require more power than the power generated by power generator 48. Therefore, the power storage device may be used to store power, and then supplement power generator 48 w hen running sensor 42, actuator 44, and/or any other components of variable flow' resistance system 25.

[0049] As discussed above, variable flow resistance system 25, and more particularly actuator 44, may be used to control or adjust an inflow' rate of fluid received into variable flow resistance system 25 through the first flow' path 38, control or adjust the restriction of fluid inflow received into variable flow resistance system 25, and/or control or adjust a drop in pressure across variable flow resistance system 25. The inflow rate of the fluid received into variable flowresistance system 25 may be controlled based upon a control signal received by variable flow resistance system 25. A control signal may be sent to variable flow resistance system 25 from a transmitter, such as a transmitter uphole or upstream of variable flow' resistance system 25, or even on or close to the surface of the well. The control signal may be wireless. For example, the control signal may be sent to variable flow resistance system 25 through the flow rate of the fluid, and more particularly by selectively fluctuating and varying the flow rate of the fluid received by variable flow' resistance system 25. A profile or pattern of flow' rate fluctuations may be used to indicate a unique control signal, such as with communications involving flow' rate telemetry. Accordingly, a transmitter, controlling the flow rate of the fluid, may be able to encode one or more control signals through flow rate fluctuations of the fluid, and a receiver, measuring the flow rate of the fluid, may be able to decode one or more controls signals through the flow' rate fluctuations of the fluid.

[0050] The transmitter is able to transmit a control signal by generating flow rate fluctuations of the fluid uphole or downstream of variable flow resistance system 25. Accordingly, to generate the flow rate fluctuations, the transmitter may include or control a choke, a bypass around a choke, a valve, a pump, or control the backpressure of the fluid at the surface, thereby selectively generating fluctuations in the flow rate of the fluid into and out of the variable flow resistance system 25.

[0051] The receiver may be able to receive a control signal by measuring flow rate fluctuations of the fluid at variable flow resistance system 25. The receiver may include or be coupled to a flow rate sensor or flow meter that is able to measure a flow rate of the fluid received into variable flow resistance system 25. For example, with respect to FIG. 2, sensor 42 may be used to measure the flow rate of the fluid received into the flow path 38. An example of a flow rate sensor 42 may include an accelerometer or a hydrophone that may be able to measure a flow rate of fluid flow, or a differential pressure gage positioned across variable flow resistance system 25 to detect a flow rate through variable flow resistance system 25.

[0052] Additionally or alternatively, power generator 48 may be used as a flow rate sensor. For example, the measured power generated by power generator 48 and the number of rotations per minute the turbine makes in power generator 48 may be combined with the measured viscosity of the fluid to calculate the flow rate of the fluid. Alternatively, the power output frequency, generator power output, frequency variance, or any combination thereof over a set of time frame may be used from power generator 48 to be used as flow rate sensor, viscosity' sensor, density sensor, fluid phase identifier, or any combination thereof.

[0053] Additionally or alternatively, a second sensor or set of sensors 50 may be positioned to measure the flow rate of the second flow path 40 (e.g.. an outlet flow path) as shown in FIG. 3. FIG. 3 shows a detailed view of a variable flow resistance system 25 in accordance with one or more embodiments of the present disclosure. The variable flow resistance system 25 in FIG. 3 may be an alternative embodiment to the variable flow resistance system 25 in FIG. 2, in which like features have like reference numbers. As shown in FIG. 3. power generator 48 may be any downhole power generator including a turbine or rotor that rotates at a rate directly related to or proportional to the fluid flow rate through power generator 48. The turbine or rotor may, thus, be used to measure the flow rate of fluid through variable flow resistance system 25. In another embodiment, power generator 48 may include a vortex generator that vibrates at a rate directly related to or proportional to the fluid flow rate through power generator 48. Power generator 48 may thus be used in addition or in alternative to a flow rate sensor to measure fluid flow rate through variable flow resistance system 25.

[0054] Furthermore, though only one sensor 42 and one actuator 44 are shown in FIG. 2, the present disclosure is not so limited, as more than one sensor 42 and/or more than one actuator 44 may be used in accordance with the present disclosure. In such embodiment, if using multiple sensors or actuators, the sensors and actuators used may be different from each other and/or may have different thresholds or tolerances than each other. For example, multiple different sensors may be used to measure different ranges of fluid flow rate through variable flow resistance system 25 or be used redundantly with respect to each other, and multiple different actuators may be used to control the inflow rate of the fluid using different techniques or at different thresholds.

[0055] The variable flow resistance system 25 may further include a controller and corresponding electronic assembly 46 to control and manage the operation of the components of variable flow resistance system 25. In one embodiment, the controller may be in communication with or coupled to the flow rate sensor 42 and actuator 44 to control actuator 44 based upon the measured flow rate and/or measured fluctuations of flow rate. The controller may be used to receive the measured flow rates and compare the measured flow rates and fluctuations with a predetermined value. Based upon the comparison of the measured flow rates with that of the predetermined value, the controller may then move actuator 44 to adjust the inflow rate of fluid received into the first flow path 38 of variable flow resistance system 25 appropriately.

[0056] As an example, in one or more embodiments, the controller may receive the flow rate fluctuations measured by sensor 42 and/or the power generator 48. The controller may then compare the measured flow rate fluctuations with one or more predetermined patterns for the flow rate fluctuations of the fluid to determine if a control signal has been included within the measured flow rate fluctuations. If, based upon the comparison, a control signal has been received through the measured flow rate or flow rate fluctuations, the controller may be used to adjust actuator 44 appropriately, such as to increase or decrease fluid flow through variable flow resistance system 25. A control signal may indicate not only what position to move actuator 44 to control the flow rate into variable flow resistance system 25, but the control signal may also indicate when to move or adjust the position of actuator 44. The control signal may be used to indicate that the wellbore is in a preliminary phase or a '‘startup mode,” in an intermediate phase, or in a final phase or a “late production mode,” in which different control parameters may be used for each of these different phases of the well.

[0057] While control signals may be received by variable flow resistance system 25, such as through measuring the flow rate of fluid received by variable flow resistance system 25 discussed above, one or more signals may also be sent from variable flow resistance system 25 to other systems or receivers. For example, by controlling fluid flow rate from atransmitter upstream, variable flow resistance system 25 may receive a control signal. Accordingly, variable flow resistance system 25 may also control the fluid flow rate such that other systems or receivers downstream, either further downhole, uphole, or even close to the surface, depending on the direction of fluid flow, may receive a signal from variable flow resistance system 25. A signal may be sent to report properties measured by variable flow resistance system 25 and/or characteristics of variable flow resistance system 25 (e.g., fluid inflow rate into variable flow resistance system 25). Further, a signal may be used to confirm that variable flow resistance system 25 is working properly and/or confirm downhole conditions of the well. The controller may, thus, use flow rate telemetry to not only receive a control signal, but may also use flow rate telemetry to control actuator 44 as desired to send a signal through the flow rate of the fluid. Alternatively, variable flow resistance system 25 may be capable of using other types of telemetry besides flow rate telemetry, such as mud-pulse telemetry⁷, pressure profde telemetry⁷, acoustic pulse telemetry, and/or pseudo-static pressure profile telemetry.

[0058] As shown and discussed above, an actuator 44 may be used with a controller to selectively adjust, enable, and restrict fluid flow- to perform as a fluid flow rate controller. In one or more embodiments, a fluid flow rate controller may be positioned in series or in parallel with a power generator 48 within a variable flow resistance system 25. Accordingly, FIGS. 4-8 show- different schematic arrangements for the fluid flow through a variable flow resistance system 25 w-ith a fluid flow rate controller 402 and a power generator 404 positioned in series or in parallel within the system.

[0059] FIG. 4 is a schematic view of variable flow resistance system 25 with fluid flow⁷ rate controller 402 and power generator 404 positioned in series within the system 400. This arrangement of variable flow⁷ resistance system 25 is similar to variable flow resistance system 25 shown in the embodiment of FIG. 2. In FIG. 4, the flow⁷ path is arranged such that fluid flows through the fluid flow⁷ rate controller 402 and then the power generator 404, as indicated by the directional arrows. Fluid may also flow⁷ in the reverse direction such that fluid flows through power generator 404 and then fluid flow rate controller 402.

[0060] In FIG. 5, a schematic view is shown of variable flow resistance system 25 with fluid flow rate controller 402 and powder generator 404 still positioned in series within variable flow resistance system 25. In this embodiment, a check valve 406 is included within variable flow⁷ resistance system 25 and is positioned in parallel with fluid flow rate controller 402. This embodiment enables fluid flow rate controller 402 to control the fluid flow⁷ rate through variable flow resistance system 25 in one direction, while power generator 404 is able to generate power from fluid flow in both directions through variable flow⁷ resistance system 25. In another embodiment, the check valve 406 may be additionally or alternatively be positioned in parallel with power generator 404. [0061] In FIG. 6, a schematic view is shown of variable flow resistance system 25 with fluid flow⁷ rate controller 402 and pow er generator 404 positioned in series within variable flow⁷ resistance system 25. In this embodiment, a nozzle 408 and/or a relief valve 410 may be included within variable flow resistance system 25. As shown, the nozzle 408 may be positioned in parallel with fluid flow⁷ rate controller 402, and relief valve 410 may be positioned in parallel with powder generator 404. Nozzle 408 is used in this embodiment to restrict but allow⁷ minimum fluid flow⁷ around fluid flow rate controller 402. This arrangement enables fluid to still flow to power generator 404 to generate power, even in a scenario when fluid flow rate controller 402 is completely closed and preventing fluid flow' therethrough. Further, relief valve 410 may be used to relieve fluid pressure above a predetermined amount around power generator 404.

[0062] In FIG. 7, a schematic view is shown of variable flow resistance system 25 with fluid flow rate controller 402 and power generator 404 positioned in parallel within variable flow resistance system 25. In this embodiment, the flow path is arranged such that fluid flows separately to fluid flow⁷ rate controller 402 and power generator 404. As such, fluid may flow to power generator 404 to generate power, even when fluid flow⁷ rate controller 402 is completely closed and preventing fluid flow therethrough.

[0063] In FIG. 8, a schematic view is shown of variable flow resistance system 25 with fluid flow rate controller 402 and pow er generator 404 positioned in parallel w ithin variable flow resistance system 25. A nozzle 408 and a relief valve 410 are also included within variable flow⁷ resistance system 25. Nozzle 408 is positioned in parallel with fluid flow rate controller 402 to restrict the amount of fluid flow to power generator 404. Further, relief valve 410 is positioned in parallel with power generator 404 to bypass power generator 404 when fluid pressure is above a predetermined amount.

[0064] Referring now to FIG. 9, a flow chart of a method 900 of controlling downhole production flow is shown. In step 902. the variable flow resistance system 25 (referring to FIG. 2) is installed in a production tubing string. The production tubing string is then disposed downhole in step 904. Variable flow' resistance system 25 may include a controller and corresponding electronic assembly 46 to control and manage the operation of the components of variable flow⁷ resistance system 25. The controller may be in communication with or coupled to the flow rate sensor 42 (referring to FIG. 2) and actuator 44 to control actuator 44 based upon the measured flow rate and/or measured fluctuations of flow' rate. The controller may be used to receive the measured flow rates and compare the measured flow rates and fluctuations with a predetermined value. Based upon the comparison of the measured flow rates with that of the predetermined value, the controller may then move actuator 44 to adjust the inflow rate of fluid received into the first flow path 38 of variable flow resistance system 25 appropriately in step 906.

[0065] If the measured flow rate fluctuations match or are similar to a predetermined pattern for the flow rate fluctuations of the fluid, this comparison may indicate that a control signal has been received by variable flow resistance system 25 (referring to FIG. 2). Controlling the inflow rate of the fluid in step 906 may then further include adjusting the inflow rate of the fluid received into the first flow path 38 based upon the comparison of the measured flow rate or flow rate fluctuations of the fluid with the predetermined value. In particular, in the example above, as the comparison of the measured flow rate with the predetermined value indicated that a control signal was received by the variable flow resistance system, the inflow fluid restriction through the variable flow resistance system may be adjusted in accordance with the direction or instructions of the control signal. Adjusting the inflow rate of the fluid may result in a variation in the inflow fluid restriction, a variation in the pressure drop across the system, or a variation in both the fluid restriction and pressure drop.

[0066] The method 900 may then further include sending a signal from variable flow resistance system 25. For example, variable flow resistance system 25 may use flow rate telemetry’ to send a signal to a component or receiver downstream, or may use other types of telemetry, such as mud-pulse telemetry', pressure profile telemetry', acoustic pulse telemetry', and/or pseudo-static pressure profile telemetry'.

[0067] Variable flow resistance system 25 includes one or more power generator 48 and may include power storage device. Power generator 48 is used to generate power for variable flow resistance system 25, and the power storage device may be used to provide stored power for variable flow resistance system 25 and/or store power generated by power generator 48 in step 908 of FIG. 9.

[0068] Modifications, additions, or omissions may be made to method 900 without departing from the scope of the present disclosure. For example, the order of the steps may be performed in a different manner than that described and some steps may be performed at the same time. Additionally, each individual step may include additional steps without departing from the scope of the present disclosure.

[0069] FIGS 10-14 are schematic views of different examples of flow meter sensors in accordance with one or more embodiments. FIG. 10 shows a schematic view of a gamma ray multiphase flow' meter 1000 which relies on a Venturi tube 1010 using differential pressure sensors 1020, a pressure sensor 1030, a temperature sensor 1040, combined with a gamma raysensor including a nuclear source 1050 and a detector 1060 to measure the flow rates of the individual phase in a given flow. The gamma ray multiphase flow may use any type of radioactive materials as nuclear source 1050 including Americium 241, Barium 133, and Cesium 137. The flow outlet 1070 is at a right angle of the flow inlet 1080 in system 1000 in FIG. 10. However, flow outlet 1070 may be at any angle of the flow inlet 1080 in other embodiments. It should be noted that FIG. 10 shows a 90° angle between flow outlet 1070 and the gamma ray sensor including a nuclear source 1050 and a detector 1060. However, any angle between the two are envisaged and could be implemented/

[0070] FIG. 1 1 A shows a schematic view of the electrodes on the outside of a tubing in accordance with one or more embodiments of the present disclosure with water and oil inside the tubing. FIG. 1 IB shows a schematic view of the cross section of the tubing with water and oil inside the tubing or pipe, and the electrode on the outside in accordance with one or more embodiments of the present disclosure. The two electrodes are coupled to form a capacitor. FIG. 11C shows a schematic view of the electronic system The amount of energy the capacitor can store, or capacitance, depends upon the volume of liquid inside the tubing. Therefore, the capacitance depends upon the volume of oil within the liquid and its flow rate. It should be noted that any of the sensors could detect and quantify the presence of oil. water, gas, and any combination thereof

[0071] FIG. 12 shows a schematic view of a magnetic inductive flow meter which operates according to the induction principle as a direct voltage is generated through the movement of a conductor in a magnetic field. As conductive brine flows through the measuring tubing, a voltage perpendicular to the magnetic field is produced which is picked up by two electrodes (labelled sender and receiver). The induced voltage is proportional to the average flow velocity of the liquid. In multiphase flow, as the quantity of gas and/or oil increases, the voltage decreases. The magnetic inductive flow meter could take some of the cross section of the flow line including from 1 % to 100 % and any number in between.

[0072] FIG. 13 shows a schematic view of a magnetic resonance flow- meter wdth the permanent magnet on each side of the tubing forming a magnetic field perpendicular to the flow' of the fluid inside the tubing.

[0073] FIG. 14 shows a schematic view of an ultrasonic flow meter in accordance with an upstream transducer and a ownstream transducer separated axially by a distance d labelled sensors spacing. The time of flight between the sender and the receiving transducer may be monitored. The ultrasonic flow' meter may measure the variance in the speed of sound through the fluid to determine which fluids are present in the flow line. [0074] FIG. 15 is an overall schematic view of the variable flow resistance system 1500. Variable flow resistance system 1500 includes atool flow tine 1502, a screen (not shown), at least one sensor 1504, PCB housing 1506. adrive system 1508. a valve 1510. generators 1512. turbines 1514, and the turbine exhausts 1516 for the fluid to return to the tool flow tine. The electrical connections are represented by the dashed arrows and the fluid flow by the arrows. The fluid from the tool flow line 1502 is filtered through a screen (not shown) to prevent any plugging of variable flow resistance system 1500. Then, the fluid goes into the common void through at least one sensor 1504 controlled at least partially by PCB housing 1506 to measure at least one of the fluid properties including viscosity, density, its phase, or any combination thereof. The fluid is then directed by valve 1510 controlled at least partially by PCB housing 1506 to generators 1512 to activate turbines inside generators 1512 to generate power for variable flow resistance system 1500. Generators 1512 may generate enough power for variable flow resistance system 1500 to be fully autonomous. The power generated by the fluid flow into 1514 generators 1512 and fluid flow out of generators 1512 through turbine exhausts 1516 into the flow line are monitored at least partially by PCB housing 1506 to calculate at least one of the fluid properties including viscosity, density, its phase, and any combination thereof. The fluid from generators 1512 is then directed from turbine exhausts 1516 to the tool flow tine.

[0075] Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions, and alterations may be made herein without departing from the spirit and scope of the disclosure as defined by the appended claims. The preceding description provides various examples of the systems and methods of use disclosed herein which may contain different method steps and alternative combinations of components. It should be understood that, although individual examples may be discussed herein, the present disclosure covers all combinations of the disclosed examples, including, without limitation, the different component combinations, method step combinations, and properties of the system. It should be understood that the compositions and methods are described in terms of '‘comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of' or “consist of’ the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces.

[0076] For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.

[0077] Therefore, the present examples are well adapted to attain the ends and advantages mentioned as ell as those that are inherent therein. The particular examples disclosed above are illustrative only and may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual examples are discussed, the disclosure covers all combinations of all of the examples. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative examples disclosed above may be altered or modified and all such variations are considered within the scope and spirit of those examples. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

CLAIMS What is claimed is:

1 . A system installed in a production tubing string comprising: a downhole power generator fluidically connected to a fluid inside the production tubing string; a sensor electrically connected to the downhole power generator, wherein the sensor measures a phase of the fluid; an electronic assembly connected to the downhole power generator and the sensor, wherein the electronic assembly communicates wirelessly with surface; and a production valve electrically connected to the electronic assembly and fluidly connected to the fluid inside the production tubing string, wherein the system controls downhole production flow' from one or more production zones of a well.

2. The system of claim 1, wherein the system is located within one module.

3. The system of claim 1, wherein the sensor comprises at least one sensor selected from a group of sensors consisting of an optical sensor, a nuclear magnetic resonance spectrometer, a gas chromatography mass spectrometer, a resistivity sensor, an impedance sensor, an electromagnetic sensor, a pressure sensor, a temperature sensor, a density sensor, a viscosity sensor, and any combination thereof.

4. The system of claim 1, wherein the system controls the downhole production flow from one or more production zones of a well based on a flow rate of the fluid calculated from the downhole power generator.

5. The system of claim 1, wherein the sensor is coupled with a flow meter.

6. The system of claim 5, wherein the sensor comprises at least one sensor selected from a group of sensors consisting of gamma ray multiphase flow meter, a capacitive flow meter, a magnetic inductive flow meter, a resonance flow meter, an ultrasonic flow meter, and any combination thereof.

7. The system of claim 1, wherein the electronic assembly is autonomous.

8. The system of claim 1, wherein the electronic assembly communicates wirelessly with surface by selectively fluctuating and vary ing a flow rate of the fluid inside the production tubing string received by a variable flow resistance system.

9. The system of claim 1, wherein the production valve is an inflow control device or an interval control valve.

10. The system of claim 1, further comprising a tracer that differentiates a water phase from an oil phase.

1 l .The system of claim 1, further comprising a tracer that releases into the fluid upon abrasion with sand.

12. A method comprising: controlling downhole production flow from one or more production zones of a well using a system installed in a production tubing string, wherein the system comprises: a downhole power generator fluidically connected to a fluid inside the production tubing string; a sensor electrically connected to the downhole power generator, wherein the sensor measures a phase of the fluid: an electronic assembly connected to the dow nhole power generator and the sensor; and a production valve electrically connected to the electronic assembly and fluidly connected to the fluid inside the production tubing string; and generating power from the downhole power generator to power at least partially the system.

13. The method of claim 12, further calculating a flow rate of the fluid inside the production tubing string using the downhole pow er generator.

14. The method of claim 12, wherein the electronic assembly is autonomous.

15, The method of claim 12, wherein the electronic assembly communicates wirelessly with surface.

16. The method of claim 12, further installing a tracer that differentiates a water phase from an oil phase.

17. The method of claim 12. wherein the system further comprises a tracer that releases into the fluid upon abrasion with sand.

18. The method of claim 12, wherein the sensor comprises at least one sensor selected from a group of sensors consisting of an optical sensor, a nuclear magnetic resonance spectrometer, a gas chromatography mass spectrometer, a resistivity sensor, an impedance sensor, an electromagnetic sensor, a pressure sensor, a temperature sensor, a density sensor, a viscosity sensor, and any combination thereof.

19. The method of claim 12, wherein the production valve is an inflow control device or an interval control valve.

20. The method of claim 12, wherein the sensor is coupled with a flow meter, and wherein the sensor comprises at least one sensor selected from a group of sensors consisting of gamma ray multiphase flow meter, a capacitive flow meter, a magnetic inductive flow meter, a resonance flow meter, an ultrasonic flow meter, and any combination thereof.