Method of Measuring the Composition of Production Fluid Flowing Through an Icd

This non-provisional application claims priority to U.S. Provisional Patent Application No. 63/637,766, filed Apr. 23, 2024, the entire disclosure of which is incorporated herein by reference.

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.

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.

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 power 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.

In some embodiments, the downhole power generator may be any variable flow resistance system, turbine, or rotor capable of generating power 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.

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.

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.

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.

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.

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 interval 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.

Turning now to the figures,shows a well systemthat can embody principles of the present disclosure. As depicted in, a wellborehas a generally vertical uncased sectionextending downwardly from casing, as well as a generally horizontal uncased sectionextending through an earth formation.

A tubular string(such as a production tubing string) is installed in the wellbore. Interconnected in the tubular stringare multiple well screens, variable flow resistance systems, and packers. The packersseal off an annulusformed radially between the tubular stringand the horizontal uncased section. In this manner, fluidsmay be produced from multiple intervals or zones of the formationvia isolated portions of the annulusbetween adjacent pairs of the packers.

Positioned between each adjacent pair of the packers, a well screenand a variable flow resistance systemare interconnected in the tubular string. The well screenfilters the fluidsflowing into the tubular stringfrom the annulus. The variable flow resistance systemvariably restricts flow of the fluidsinto the tubular string, based on certain characteristics of the fluids.

At this point, it should be noted that the well systemis 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, or components thereof, depicted in the drawings or described herein.

For example, it is not necessary in keeping with the principles of this disclosure for the wellboreto include a generally vertical uncased sectionor a generally horizontal uncased section, 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 fluidsto be only produced from the formationas, in other examples, fluids could be injected into a formation, such as injected through the tubular stringand out into the formation, or fluids could be both injected into and produced from a formation, etc. Further, it is not necessary for one each of the well screenand variable flow resistance systemto be positioned between each adjacent pair of the packers. It is not necessary for a single variable flow resistance systemto be used in conjunction with a single well screen. Any number, arrangement and/or combination of these components may be used.

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

It is not necessary for the well screens, variable flow resistance systems, packersor any other components of the tubular stringto be positioned in vertical uncased sectionand horizontal uncased sectionof the wellbore. Any section of the wellboremay be cased or uncased, and any portion of the tubular stringmay be positioned in an uncased or cased section of the wellbore, in keeping with the principles of this disclosure.

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.

It will be appreciated by those skilled in the art that it would be beneficial to be able to regulate flow of the fluidsinto the tubular stringfrom each zone of the formation, for example, to prevent water coningor gas coningin 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.

Examples of a variable flow resistance systemsdescribed 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).

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.

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.

Referring now to, a schematic view of a variable flow resistance systemin accordance with one or more embodiments of the present disclosure is shown. The variable flow resistance systemmay include a sensor, an actuator, an electronic assembly, and a power generator. In this example, a fluid(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(referring to), and may then flow into a first flow path(e.g., an inlet flow path) of the variable flow resistance system. 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 fluidthrough the variable flow resistance systemis resisted to control a flow rate of the fluid flowing through variable flow resistance system. The fluidmay then be discharged from the variable flow resistance system, such as to an interior or exterior of the tubular string(referring to) via a second flow path(e.g., an outlet flow path). As used herein, the first flow pathand the second flow pathmay 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 fluidmay be reversed, such as during injection applications, through variable flow resistance systemsuch that the first flow pathand the second flow pathmay be generally described and function as an outlet flow path and an inlet flow path, respectively.

In other examples, well screen(referring to) may not be used in conjunction with variable flow resistance system(e.g., in injection operations), the fluidcould flow in an opposite direction through the various elements of the well system(referring to) (e.g., in injection operations), a single variable flow resistance systemcould 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 systemprior to flowing through well screen, any other components could be interconnected upstream or downstream of well screenand/or variable flow resistance system, 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.

The variable flow resistance systemis depicted in simplified form in, but in a preferred example, variable flow resistance systemmay include various passages and devices for performing various functions, as described more fully below. In addition, variable flow resistance systemat least partially extends circumferentially about tubular string(referring to), or variable flow resistance systemmay be formed in a wall of a tubular structure interconnected as part of the tubular string.

In other examples, variable flow resistance systemmay not extend circumferentially about a tubular string or be formed in a wall of a tubular structure. For example, variable flow resistance systemcould be formed in a flat structure, etc. Variable flow resistance systemcould be in a separate housing that is attached to tubular string(referring to), or it could be oriented so that the axis of second flow pathis parallel to the axis of tubular string. Variable flow resistance systemcould 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 systemmay be used in keeping with the principles of this disclosure.

Referring now back to, variable flow resistance systemincludes the first flow pathto receive fluid into variable flow resistance systemand a second flow pathto send fluid out of variable flow resistance system. When fluid exits variable flow resistance system, 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. The variable flow resistance systemmay further include a sensor, an actuator, an electronic assembly, and a power generator. As described above, sensoris included to measure one or more properties or characteristics of the fluid received into variable flow resistance system, such as measure the flow rate of the fluid received into variable flow resistance system. Though not so limited, and as discussed below, sensormay be positioned near or within the first flow pathto measure the property or characteristic of the fluid received into variable flow resistance systemthrough the first flow path.

Actuatormay 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). Actuatormay control or adjust an inflow rate of fluid received into variable flow resistance systemand the first flow path. Additionally or alternatively, actuatormay control or adjust the restriction of fluid inflow received into variable flow resistance systemand the first flow pathand/or control or adjust a drop in pressure between first flow pathand second flow path. For example, actuatormay be positioned or included within variable flow resistance systemto extend into and retract from the fluid flow path extending and formed through variable flow resistance system. To increase the inflow rate of the fluid, or decrease the inflow fluid restriction or pressure drop across variable flow resistance system, actuatormay retract to enable more fluid to flow through the fluid flow path of variable flow resistance system. To decrease the inflow rate of the fluid, or increase the inflow fluid restriction or pressure drop across variable flow resistance system, actuatormay extend to restrict the fluid flow through the fluid flow path of variable flow resistance system. Further, in one or more embodiments, actuatormay be used to fully stop or inhibit the fluid flow through the fluid flow path of variable flow resistance system. For example, if variable flow resistance systemis turned or powered off, actuatormay fully extend to prevent fluid flow through the fluid flow path of variable flow resistance system. Accordingly, actuatormay 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. 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.

Actuatormay include a mechanical actuator (e.g., a screw assembly), an electrical actuator (e.g., piezoelectric actuator, electric motor), a hydraulic 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, actuatormay include a linear or axially driven actuator, in which actuatorinteracts with an orifice included in the first flow pathto operate as an adjustable valve and control the inflow rate of the fluid.

Still referring to, variable flow resistance systemmay include one or more power sources. For example, variable flow resistance systemmay include a power generatorand/or a power storage device (not shown). Power generatormay be any downhole power generator described above. Power generatormay be used to generate power for variable flow resistance system, and the power storage device may be used to provide stored power for variable flow resistance systemand/or store power generated by power generator. In one embodiment, power generatormay include a turbine and may be able to generate power from fluid received into the first flow pathand flowing through variable flow resistance system. Power generatormay 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 systemand/or from other energy sources present downhole (e.g., temperature and/or pressure sources).

The power storage device may be included within electronic assemblyfor variable flow resistance systemand may be used to provide stored power. In one embodiment, the power storage device may be able to store power generated by power generatorand provide this stored power for variable flow resistance system. 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, sensorand/or actuatorof variable flow resistance systemmay require more power than the power generated by power generator. Therefore, the power storage device may be used to store power, and then supplement power generatorwhen running sensor, actuator, and/or any other components of variable flow resistance system.

As discussed above, variable flow resistance system, and more particularly actuator, may be used to control or adjust an inflow rate of fluid received into variable flow resistance systemthrough the first flow path, control or adjust the restriction of fluid inflow received into variable flow resistance system, and/or control or adjust a drop in pressure across variable flow resistance system. The inflow rate of the fluid received into variable flow resistance systemmay be controlled based upon a control signal received by variable flow resistance system. A control signal may be sent to variable flow resistance systemfrom a transmitter, such as a transmitter uphole or upstream of variable flow resistance system, 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 systemthrough 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. 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.

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. 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.

The receiver may be able to receive a control signal by measuring flow rate fluctuations of the fluid at variable flow resistance system. 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. For example, with respect to, sensormay be used to measure the flow rate of the fluid received into the flow path. An example of a flow rate sensormay 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 systemto detect a flow rate through variable flow resistance system.

Additionally or alternatively, power generatormay be used as a flow rate sensor. For example, the measured power generated by power generatorand the number of rotations per minute the turbine makes in power generatormay 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 generatorto be used as flow rate sensor, viscosity sensor, density sensor, fluid phase identifier, or any combination thereof.

Additionally or alternatively, a second sensor or set of sensorsmay be positioned to measure the flow rate of the second flow path(e.g., an outlet flow path) as shown in.shows a detailed view of a variable flow resistance systemin accordance with one or more embodiments of the present disclosure. The variable flow resistance systeminmay be an alternative embodiment to the variable flow resistance systemin, in which like features have like reference numbers. As shown in, power generatormay 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. The turbine or rotor may, thus, be used to measure the flow rate of fluid through variable flow resistance system. In another embodiment, power generatormay include a vortex generator that vibrates at a rate directly related to or proportional to the fluid flow rate through power generator. Power generatormay thus be used in addition or in alternative to a flow rate sensor to measure fluid flow rate through variable flow resistance system.

Furthermore, though only one sensorand one actuatorare shown in, the present disclosure is not so limited, as more than one sensorand/or more than one actuatormay 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 systemor 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.

The variable flow resistance systemmay further include a controller and corresponding electronic assemblyto control and manage the operation of the components of variable flow resistance system. In one embodiment, the controller may be in communication with or coupled to the flow rate sensorand actuatorto control actuatorbased 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 actuatorto adjust the inflow rate of fluid received into the first flow pathof variable flow resistance systemappropriately.

As an example, in one or more embodiments, the controller may receive the flow rate fluctuations measured by sensorand/or the power generator. 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 actuatorappropriately, such as to increase or decrease fluid flow through variable flow resistance system. A control signal may indicate not only what position to move actuatorto control the flow rate into variable flow resistance system, but the control signal may also indicate when to move or adjust the position of actuator. 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.

While control signals may be received by variable flow resistance system, such as through measuring the flow rate of fluid received by variable flow resistance systemdiscussed above, one or more signals may also be sent from variable flow resistance systemto other systems or receivers. For example, by controlling fluid flow rate from a transmitter upstream, variable flow resistance systemmay receive a control signal. Accordingly, variable flow resistance systemmay 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. A signal may be sent to report properties measured by variable flow resistance systemand/or characteristics of variable flow resistance system(e.g., fluid inflow rate into variable flow resistance system). Further, a signal may be used to confirm that variable flow resistance systemis 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 actuatoras desired to send a signal through the flow rate of the fluid. Alternatively, variable flow resistance systemmay be capable of using other types of telemetry besides flow rate telemetry, such as mud-pulse telemetry, pressure profile telemetry, acoustic pulse telemetry, and/or pseudo-static pressure profile telemetry.

As shown and discussed above, an actuatormay 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 generatorwithin a variable flow resistance system. Accordingly,show different schematic arrangements for the fluid flow through a variable flow resistance systemwith a fluid flow rate controllerand a power generatorpositioned in series or in parallel within the system.

is a schematic view of variable flow resistance systemwith fluid flow rate controllerand power generatorpositioned in series within the system. This arrangement of variable flow resistance systemis similar to variable flow resistance systemshown in the embodiment of. In, the flow path is arranged such that fluid flows through the fluid flow rate controllerand then the power generator, as indicated by the directional arrows. Fluid may also flow in the reverse direction such that fluid flows through power generatorand then fluid flow rate controller.

In, a schematic view is shown of variable flow resistance systemwith fluid flow rate controllerand power generatorstill positioned in series within variable flow resistance system. In this embodiment, a check valveis included within variable flow resistance systemand is positioned in parallel with fluid flow rate controller. This embodiment enables fluid flow rate controllerto control the fluid flow rate through variable flow resistance systemin one direction, while power generatoris able to generate power from fluid flow in both directions through variable flow resistance system. In another embodiment, the check valvemay be additionally or alternatively be positioned in parallel with power generator.

In, a schematic view is shown of variable flow resistance systemwith fluid flow rate controllerand power generatorpositioned in series within variable flow resistance system. In this embodiment, a nozzleand/or a relief valvemay be included within variable flow resistance system. As shown, the nozzlemay be positioned in parallel with fluid flow rate controller, and relief valvemay be positioned in parallel with power generator. Nozzleis used in this embodiment to restrict but allow minimum fluid flow around fluid flow rate controller. This arrangement enables fluid to still flow to power generatorto generate power, even in a scenario when fluid flow rate controlleris completely closed and preventing fluid flow therethrough. Further, relief valvemay be used to relieve fluid pressure above a predetermined amount around power generator.

In, a schematic view is shown of variable flow resistance systemwith fluid flow rate controllerand power generatorpositioned in parallel within variable flow resistance system. In this embodiment, the flow path is arranged such that fluid flows separately to fluid flow rate controllerand power generator. As such, fluid may flow to power generatorto generate power, even when fluid flow rate controlleris completely closed and preventing fluid flow therethrough.

In, a schematic view is shown of variable flow resistance systemwith fluid flow rate controllerand power generatorpositioned in parallel within variable flow resistance system. A nozzleand a relief valveare also included within variable flow resistance system. Nozzleis positioned in parallel with fluid flow rate controllerto restrict the amount of fluid flow to power generator. Further, relief valveis positioned in parallel with power generatorto bypass power generatorwhen fluid pressure is above a predetermined amount.

Referring now to, a flowchart of a methodof controlling downhole production flow is shown. In step, the variable flow resistance system(referring to) is installed in a production tubing string. The production tubing string is then disposed downhole in step. Variable flow resistance systemmay include a controller and corresponding electronic assemblyto control and manage the operation of the components of variable flow resistance system. The controller may be in communication with or coupled to the flow rate sensor(referring to) and actuatorto control actuatorbased 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 actuatorto adjust the inflow rate of fluid received into the first flow pathof variable flow resistance systemappropriately in step.

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(referring to). Controlling the inflow rate of the fluid in stepmay then further include adjusting the inflow rate of the fluid received into the first flow pathbased 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.

The methodmay then further include sending a signal from variable flow resistance system. For example, variable flow resistance systemmay 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.

Variable flow resistance systemincludes one or more power generatorand may include power storage device. Power generatoris used to generate power for variable flow resistance system, and the power storage device may be used to provide stored power for variable flow resistance systemand/or store power generated by power generatorin stepof.