Apparatus, system and method for regulating fluid flow through a well system

Abstract

Some embodiments of the present disclosure relate to an apparatus for regulating flow of a fluid flowing through the apparatus when deployed and retained within a well. The apparatus may comprise a retaining assembly for retaining the apparatus in a desired position within a wellbore; a mandrel with a first end and a second end, defining a longitudinal axis therebetween, the mandrel defining one or more orifices for fluid communication between inside the mandrel and outside the mandrel; and, a shift sleeve in nested arrangement with the mandrel, the shift sleeve defining one or more orifices for providing fluid communication between an inside of the shift sleeve and outside the shift sleeve. The shift sleeve is shiftable in response to changes in a property of a fluid flowing through the apparatus, wherein shifting of the shift sleeve changes a cross- sectional flow area of one of the one or more orifices.

Description

APPARATUS, SYSTEM AND METHOD FOR REGULATING FLUID FLOW THROUGH A WELL SYSTEM TECHNICAL FIELD

[0001] This disclosure generally relates to collecting geothermal energy. Inparticular, this disclosure relates to apparatus, systems and methods of increasing the efficiency of conducting fluids through a well or well system. BACKGROUND

[0002] Well systems are an established way of conducting fluids from oneposition to another, for example between the surface of the ground and a geologic formation. In particular, geothermal systems are known for collecting geothermal energy from the heat within the core of the earth. For example, a fluid can be directed through a drilled wellbore that extends through a portion of the earth’s geological substructure. The fluid is then heated and depending on the degree to which the fluid is heated it can be used for providing heat to industrial processes, human structures, water and / or to generate other usable forms of energy, such as electricity.

[0003] However, if multiple well bores are drilled through a geologicalformation but connected to one source of pressurized fluid, then there can be an unequal flow distribution between the different bores or fracture networks within the geological network. As shown in FIG. A, there are three lines, line A depicts a hypothetical production efficiency when there is ideal flow distribution through all bores of a given geothermal system, line B depicts a hypothetical production efficiency when there is uneven flow distribution; and, line C depicts a hypothetical production efficiency when there is a short-circuit that has occurred and substantially all flow is passing through a select few bores, a single bore or a fracture within the geological formation. A decreased production efficiency may be caused by an increased thermal draw down in one or more portions of the geothermal system.

[0004] As such, it may be desirable to establish new apparatus, systems andmethods for enhancing flow distribution through a geothermal wellbore or systems of wellbores so as to achieve a greater efficiency.SUMMARY

[0005] Some embodiments of the present disclosure relate to an apparatus forregulating flow of a fluid flowing through the apparatus when deployed and retained within a wellbore. The apparatus may comprise a retaining assembly for retaining the apparatus in a desired position within a wellbore; a mandrel with a first end and a second end, defining a longitudinal axis therebetween, the mandrel defining one or more orifices for fluid communication between inside the mandrel and outside the mandrel; and, a shift sleeve in nested arrangement with the mandrel, the shift sleeve defining one or more further orifices for providing fluid communication between an inside of the shift sleeve and outside the shift sleeve. The shift sleeve is shiftable in response to changes in a property of a fluid flowing through the apparatus, wherein shifting of the shift sleeve changes a cross-sectional flow area of at least one of the one or more orifices.

[0006] Some embodiments of the present disclosure relate to a well systemcomprising a wellbore with the apparatus deployed and retained at a desired position within the wellbore. The apparatus may comprise a retaining assembly for retaining the apparatus in a desired position within a wellbore; a mandrel with a first end and a second end, defining a longitudinal axis therebetween, the mandrel defining one or more orifices for fluid communication between inside the mandrel and outside the mandrel; and, a shift sleeve in nested arrangement with the mandrel, the shift sleeve defining one or more orifices for providing fluid communication between an inside of the shift sleeve and outside the shift sleeve. The shift sleeve is shiftable in response to changes in a property of a fluid flowing through the apparatus, wherein shifting of the shift sleeve changes a cross-sectional flow area of at least one of the one or more orifices.

[0007] Some embodiments of the present disclosure relate to a method ofregulating fluid flow through a wellbore. The method may include the steps of: defining one or more fluid flow paths for conducting fluid within the wellbore; changing a cross-sectional flow area of one or more of the one or more fluid flow paths in response to a change in a change in a of the fluid.

[0008] In some embodiments of the present disclosure the apparatus may beconfigured to be deployed and retained at a desired position within a wellbore when the wellbore is not cased or lined. In some embodiments of the present disclosure, the apparatus is configured to be deployed and retained at a desired position within a lined or cased wellbore. The apparatus may be deployed by wireline, a well tractor, coiled tubing, e-coil, jointed tubing, by being threaded onto jointed tubing, by being threaded onto casing or liner or any combination thereof or any other mechanism or system for deploying devices or tools in a well. In some embodiments of the present disclosure, the apparatus may provide one or more flow paths that cause an increase, a decrease or both in the pressure of the fluid flowing through the one or more flow paths. In some embodiments of the present disclosure, the apparatus may provide one or more markers that are releasable into the fluid for capture downstream of the apparatus. The one or more markers, once captured, can provide information to operators regarding the environment at the apparatus. For example, the one or more markers may indicate the temperature of the fluid, the flow rate, fluid pressure or combinations thereof.

[0009] Some embodiments of the present disclosure relate to a system thatincludes one or more of the apparatus for regulating flow of a fluid flowing through a wellbore. In such systems, multiple apparatus may act independent of each other in order to enhance the balance of the fluid flow across multiple wellbores and / or a fracture and / or network of fractures.

[0010] Some embodiments of the present disclosure relate to a method forregulating flow of a fluid flowing through a wellbore or multiple wellbores. Some embodiments of the present disclosure relate to methods of establishing one or more fluid flow paths within a well system, wherein a cross-sectional flow area of one or more of the fluid flow paths can change. For example, the cross-sectional flow area may change in response to a pressure drop within the fluid flowing through the apparatus. In some embodiments of the present disclosure, the cross-sectional flow area may change autonomously in response to changes in one or more properties of the fluid flowing through the flow control apparatus, such as but not limited to: pressure, a pressure differential across the apparatus, flow rates or any combination thereof. When multiple flow control apparatus are and retained, each at a desired locationwithin the well system, the autonomous changing of cross-sectional flow area of each of the apparatus may enhance the balancing of fluid flow throughout portions of or the entirety of the well system.

[0011] Some embodiments of the present disclosure relate to a method ofproviding information to an operator of a well system regarding events that are occurring downhole. For example, information regarding events that relate to changes in pressure and / or temperature can be conveyed to the operator by one or more tracers being released into the fluid flow of the well system. In some embodiments of the present disclosure, the tracer may be a chemical tracer or a physical token.

[0012] Without being bound by any particular theory, the embodiments of thepresent disclosure may enhance production efficiency of a well system. As is understood by those skilled in the art, the flow of fluid through two or more conduits that are in fluid communication can vary to inherent differences in fluid resistance between the two or more conduits. Such inherent differences result in a greater amount of the fluid flowing through the conduit with the lowest resistance, which results in other conduits receiving less or no fluid flow. That imbalance poses practical problems for managing and optimizing fluid flow through the well system. The embodiments of the present disclosure relate to a self-adjusting flow control apparatus that can be installed in various well systems that limits the fluid flow therethrough to a calibrated value through a specific flow path using one or more variable area orifices. The embodiments of the present disclosure can be used to reduce fluid losses by shutting off low pressure areas in the formation in both injector and production wells if the pressure drop across the orifices exceeds a pre-calibrated value. BRIEF DESCRIPTION OF THE DRAWINGS

[0013] These and other features of the present disclosure will become moreapparent in the following detailed description in which reference is made to the appended drawings.

[0014] FIG. 1 shows a side-elevation view of an apparatus in a first operationalposition, according to embodiments of the disclosure.

[0015] FIG. 2 shows a side-elevation of the apparatus of FIG. 1 in a secondoperational position.

[0016] FIG. 3 shows a side-elevation view of an apparatus in a first operationalposition, according to embodiments of the present disclosure.

[0017] FIG. 4 shows a side-elevation of the apparatus of FIG. 3 in a secondoperational position.

[0018] FIG. 5 shows a side-elevation of the apparatus of FIG. 3 in a thirdoperational position.

[0019] FIG. 6 shows a side-elevation view of an apparatus in a first operationalposition, according to embodiments of the present disclosure.

[0020] FIG. 7 shows a side-elevation of the apparatus of FIG. 6 in a secondoperational position.

[0021] FIG. 8 shows a side-elevation of the apparatus of FIG. 6 in a thirdoperational position.

[0022] FIG. 9 shows a side-elevation of the apparatus of FIG. 3 in a fourthoperational position.

[0023] FIG. 10 shows a side-elevation view of an apparatus in a firstoperational position, according to embodiments of the present disclosure.

[0024] FIG. 11 shows a side-elevation of the apparatus of FIG. 10 in a secondoperational position.

[0025] FIG. 12 shows a side-elevation of the apparatus of FIG. 10 in a thirdoperational position.

[0026] FIG. 13 shows a side-elevation view of an apparatus in a firstoperational position, according to embodiments of the present disclosure.

[0027] FIG. 14 shows a side-elevation of the apparatus of FIG. 13 in a secondoperational position.

[0028] FIG. 15 shows a side-elevation of the apparatus of FIG. 13 in a thirdoperational position.

[0029] FIG. 16 shows a side-elevation view of an apparatus in a firstoperational position, according to embodiments of the present disclosure.

[0030] FIG. 17 shows a side-elevation of the apparatus of FIG. 16 in a secondoperational position.

[0031] FIG. 18 shows a side-elevation of the apparatus of FIG. 16 in a thirdoperational position.

[0032] FIG. 19 shows a top-plan view of a marker chamber with a plurality ofmarkers housed therein.

[0033] FIG. 20 is a side-view schematic of a well system with two primary,open wellbores and naturally occurring fractures.

[0034] FIG. 21 shows the schematic of FIG. 20 with apparatus, according tothe present disclosure, deployed and retained in a desired position within the wellbores.

[0035] FIG. 22 shows an isometric view of a casing arrangement within a wellsystem with two primary cased wellbores and four legs of cased wellbores therebetween and a top-plan view of the casing arrangement.

[0036] FIG. 23 shows a top plan view of the casing arrangement of FIG. 22with an apparatus, according to the embodiments of the present disclosure, deployed and retained at a desired position within the intermediary cased wellbores.

[0037] FIG. 24 shows a side-view schematic of a well system with two primarycased-wellbores with five production zones (1-5) and different examples of communicating fractures that extend between the two primary cased-wellbores.

[0038] FIG. 25 shows the side-view schematic of FIG. 24 with an apparatus,according to the embodiments of the present disclosure, deployed and retained at a desired position within each production zone.

[0039] FIG. 26 is a line graph depicting a theoretical pressure drop over flowrate through an apparatus, according to the embodiments of the present disclosure, without a shut-off capability.

[0040] FIG. 27 is a line graph depicting a theoretical pressure drop over flowrate through an apparatus, according to the embodiments of the present disclosure, with a shut-off capability.

[0041] FIG. 28 is a line graph depicting a theoretical pressure drop over flowrate through an apparatus, according to the embodiments of the present disclosure, with a reverse flow shut-off capability.

[0042] FIG. 29 is a line graph depicting a theoretical pressure drop over flowrate through a known flow control device. DETAILED DESCRIPTION

[0043] The embodiments of the present disclosure relate to an apparatus, asystem and a method for regulating the flow of a fluid through a well of a well system. As non-limiting examples of such well systems, at least the following are contemplated by this disclosure: in-situ recovery mining, solution mining, carbon dioxide (CO2) injection, water injection, hydrocarbon recovery, geothermal wells and any other subsurface well application that could benefit from regulating fluid flow at predetermined rates through two or more conduits of the well system. The embodiments of the present disclosure rely upon providing a flow path for the well borne fluid, where such flow path changes one or more properties of the fluid. In some embodiments of the present disclosure, there may be one or two or more flow paths created for changing the one or more properties of the fluid. The one or more properties of the fluid include, but are not limited to: pressure, a pressure differential across the apparatus, flow rates or any combination thereof. For example, the fluidflowing through the well may be forced to flow through an apparatus and / or a system of the present disclosure, where such system comprises more than one of such apparatus. The apparatus defines one or more flow paths that cause a change in the pressure of the flowing fluid by changing the pressure loss of fluid moving through at least one flow path of the apparatus so as to maintain a desired flow rate through the apparatus. Furthermore, the apparatus is susceptible to physical forces caused by the flow of the fluid and / or the change in the one or more properties of the flowing fluid. In response to those physical forces, the apparatus can shift from one operational position to another, which changes the pressure loss of fluid moving through at least one flow path of the apparatus. In some embodiments of the present disclosure, the apparatus has the potential to shift between one, two, three, four or more operational positions. In some embodiments of the present disclosure, in one operational position the apparatus may provide one or more flow paths for the flowing fluid to flow through. In another operational position the apparatus may provide a different flow path for the flowing fluid to flow through. In another operational position the apparatus may block one or more of the flow paths therethrough. In one or other operational positions, the apparatus may release a first marker into the fluid. The marker can be captured downstream of the apparatus to provide information to the operator of the well system. The information may relate to the pressure, flow rate, temperature or another property of the fluid flowing through the apparatus and / or the system. In a further operational position, the apparatus may release a second marker. In short, the operational position of the apparatus may cause one or more markers to be released into the fluid flowing through the apparatus and the operational position of the apparatus may be determined by one or more flow properties of the fluid.

[0044] FIG. 1 through FIG. 12 of the present disclosure relate to examples of anapparatus, according to the embodiments of the present disclosure. The apparatus may be deployed within a geothermal wellbore that is without an internal tubular liner or casing, which is referred to herein as an open wellbore. The apparatus may be deployed and retained in a desired position within the open wellbore. This apparatus may be referred to as an in-line flow control device.

[0045] FIG. 13 through FIG. 15 of the present disclosure relate to anotherexample of an apparatus, according to embodiments of the present disclosure. This apparatus may be deployed within a lined or cased geothermal wellbore. The apparatus may be deployed and retained in a desired position within the wellbore. The apparatus may be positioned within a primary injector wellbore of a geothermal well system and the apparatus may regulate the flow of injected fluids out of the injector wellbore. In some embodiments of the present disclosure, this apparatus may be referred to as an outflow control device.

[0046] FIG. 16 through FIG. 18 of the present disclosure relate to anotherexample apparatus, according to embodiments of the present disclosure. This apparatus may be deployed within a lined or cased geothermal wellbore. The apparatus may be deployed and retained in a desired position within the wellbore. The apparatus may be positioned within a primary production wellbore of a geothermal well system and the apparatus may regulate the flow of injected fluids into the production wellbore. In some embodiments of the present disclosure, this apparatus may be referred to as an inflow control device.

[0047] The embodiments of the present disclosure will now be described withspecific reference to the figures, which show representations of the apparatus, systems and methods according to the present disclosure.

[0048] Referring to the non-limiting example of FIG. 1, an apparatus 10 isshown. The apparatus 10 comprises a shift sleeve 12, an outer mandrel 14 and a retaining assembly 16. The shift sleeve 12 may be in a nested arrangement within or upon the mandrel 14. The apparatus 10 is shown deployed and retained in an open wellbore 102 with one portion 102A of the wellbore 102 defined as the upstream or uphole portion / side and another portion 102B defined as the downstream or downhole portion / side. As such, when deployed and retained in the open hole, the apparatus 10 has an uphole end 10A, which may also be referred to as a flow entry point and a downhole end 10B, which may also be referred to as the flow exit point. As such, when fluid is flowing through the wellbore 102, it generally flows in a direction of uphole to downhole and through the 10. At the uphole end 10A, theapparatus may define a shoulder 13, which may also be referred to as a spring retainer. The mandrel 14 is positioned about the sleeve 12 with each component defining a shoulder that engages a shoulder of the other component so as to prevent the mandrel 14 from moving downhole without the sleeve 12 and to prevent the sleeve 12 from moving uphole without the mandrel 14. The apparatus 10 further comprises a biasing member 15, which may be referred to as a spring in some embodiments of the present disclosure. The biasing member 15 is positioned about the sleeve 12 between the shoulder 13 and the uphole end of the mandrel 14. The biasing member 15 generates a biasing force that acts to increase the distance between the shoulder 13 and the uphole end of the mandrel 14. The apparatus 10 defines two flow paths. A first flow path extends entirely internal to the apparatus 10 from the uphole end 10A of the apparatus 10 to the downhole end 10B. A second flow path extends partially external and partially internal to the apparatus 10. The external portion of the second flow path is defined between the outer surface of the apparatus 10 and the inner surface of the wall of the well102. The second flow then passes through an aperture 18 defined in the mandrel 14 and the sleeve 12 so as to merge with the first flow path within the apparatus 10.

[0049] In some embodiments of the present disclosure, the inner surface of thesleeve 12 may define a flow regulating feature that changes one or more properties of the fluid flowing through the first flow path. In some embodiments of the present disclosure, the flow regulating feature may cause a pressure drop, which may also be referred to as a pressure loss, as the fluid passes through the feature. For example, the feature may optionally comprise a converging portion 10B, a diverging portion 10D with a straight portion therebetween. As the fluid flows through the first flow path it loses pressure when it enters a second straight portion 10E of the apparatus 10. In other embodiments of the present disclosure, the sleeve 12 may not have the converging portion 10B and / or the diverging portion 10D so that as fluid flows through the first flow path it is not subjected to a pressure loss due to the portions 10D, 10E described above.

[0050] It is within portion 10E of the apparatus 10 where the fluid within thesecond flow path mixes with the fluid in first flow path (as represented by the arrowZ). The fluid within portion 10E then passes into a final internal portion 10F of the apparatus 10. In some embodiments of the present disclosure, the portion 10F is straight and has a larger cross-sectional flow area that the portion 10E. As the fluid passes into portion 10F it may lose further pressure.

[0051] The aperture 18 is defined by a side entry port 22, which is defined bythe mandrel 14 and may also be referred to as a side entry orifice. The aperture 18 is also defined by a port that extends through the sliding sleeve 12. A sliding slot 24 may be held within the aperture 18 by a retaining ring 20. As depicted in the lower left hand and right hand inserts of FIG. 1, the sliding slot 24 may have a predetermined shape that defines an exposed flow area 30.

[0052] The view in the lower left hand is taken from outside the apparatus 10looking into the side entry port 22 and the view in the lower right hand insert is taken from inside the apparatus 10 looking out of the aperture 18. As such, all of the fluid within the second fluid path must pass through both the exposed flow area 30 of the sliding slot 24 and the side entry port 22, as such at any given point in time the alignment of the sliding slot 24 relative to the port 22 defines the cross-sectional flow area of the second fluid path.

[0053] As but one non-limiting example, the predetermined shape of the slidingslot 24 may be substantially triangular with a larger end of the shape being defined by a substantially straight line, a smaller end of the shape (opposite to the large end) may be defined by a semi-circle, with the sides in between the larger end and the smaller end defined by an interpolated curve where the sides get continuously closer together as the shape goes from the larger end to the smaller end. The shape is defined in such a way to allow the pressure drop changes that correlate to the fluid velocity squared (power of 2) to be directly connected to the spring rate that changes the spring force at a constant rate (power of 1). It is understood by those skilled in the art that the predetermined shape can be designed based upon a range of pressure loss that it is desired to impose upon the fluid flowing through the second flow path. The design of the predetermined shape is discussed further in the examples below.

[0054] Because the position of exposed flow area 30 relative to the aperture 18can change based upon the operational position of the apparatus 10, the fluid flowing through the second flow path may have a first pressure loss at a first time period or flow rate (as the case may be) and a second pressure loss at a second time period or flow rate (as the case may be) because the position of the sliding slot 24 relative to the aperture 18. For example, when the position of the sliding sleeve 12 changes, the exposed flow area 30 that is aligned with the aperture 18 will change, thus changing the cross-sectional flow area of the second flow path. This change in the cross-sectional flow area of the second flow area will change (i.e. increase or decrease) the pressure lost by the fluid flowing through the second flow path.

[0055] Without being bound by any theory, when there is a change in the flowrate within the well system, the operational position of the apparatus 10, 500, 700 can automatically. The term “automatically” is used herein to reflect that the balance between the biasing force of the biasing member and the pressure differential across the apparatus can cause changes in the operational position of the apparatus 10, 500, 700 without any intervention other than the properties of the fluid flowing in the well system. As such, if there is an overall increase in flow rate through the well system, the operational position of the apparatus 10, 500, 700 will automatically change to cause an amplified increase in pressure loss that is localized to the apparatus 10, 500, 700 which will mitigate or reduce the localized increase in flow rate above a predetermined target flow rate value. Conversely, when there is an overall decrease in the flow rate within the well system, the operational position of the apparatus 10 will automatically change to cause a de-amplified decrease in pressure loss that is localized to the apparatus 10, 500, 700 which will mitigate or reduce the localized decrease in flow rate below a pre- determined target value.

[0056] The retaining assembly 16 is connected to a portion of the outer surfaceof the mandrel 14. The retaining assembly 16 comprises an open-hole seal 16A that extends between the outer surface of the mandrel 14 to engage with the inner surface of the open hole 102. The retaining assembly 16 further comprises one or more slip cones 16C and one or more slips 16D where the one or more slip cones 16C can slide underneath the slips 16D causing the slips to expand outwardly to engage the innersurface of the open wellbore 102, this may be referred to as the engaged position. When the slips 16D are engaged with the inner wall of the open wellbore 102, the apparatus 10 is retained in the desired location.

[0057] As will be appreciated by those skilled in the art, the apparatus 10 maybe deployed and retained in the desired position by known methods and tools, such as a setting tool (not shown) that compresses the retaining assembly 16 from a non- engaging position and then when actuated or released by the setting tool the retaining assembly 16 can move into the engaged position.

[0058] As depicted in FIG. 1, the apparatus 10 is deployed and retained in thedesired position within the open wellbore and it is in a first operational position. In the first operational position the apparatus 10 is fully extended, meaning the biasing force generated by the biasing member 15 is the prevailing physical force influencing the operational position of the apparatus 10. In the first operational position, the relative position of the sliding sleeve 12 and the mandrel 14 is such that the sliding slot 24 defines a fully open or substantially fully open exposed flow area 30.

[0059] In the non-limiting example of FIG. 2, the apparatus 10 is depicted in asecond operational position, in which the pressure of the fluid striking the uphole end 10A of the apparatus 10 combined with the pressure loss caused by the fluid flowing along the first and second flow paths generated a sufficient combined force so as to overcome the biasing force such that the sleeve 12 shifts downhole, compressing the biasing member 15 and bringing the shoulder 13 closer to the uphole end of the mandrel 14. The combined force is generated in part by the fluid flowing through the open wellbore 102 acts against the uphole end of the apparatus 10, where the cross- sectional area of the sleeve 12 and the shoulder 13 act like a piston face. As will be understood by those skilled in the art, the fluid pressure acting on the shoulder 13 is equalized on both sides and the differential fluid pressure acts across the sleeve 12 and the orifice 10B Another part of the combined force is caused by the pressure drop that occurs within the fluid within the portion 10F, which generates a force that acts on the downhole end of the sleeve 12. When the apparatus 10 is in the second operational position, the position of the sleeve 12 relative to the mandrel 14 causes the exposedflow area 30 through the slot 24 to reduce, which in turn causes a further loss of pressure within the fluid in the second fluid path. As will be appreciated by those skilled in the art, the apparatus 10 comprises various sealing members 26, which may also be referred to as seals, that are positioned between the sleeve 12 and the mandrel 14 so as to prevent fluid from flowing between the two components of the apparatus and so as to force the fluid to flow along the first or second flow path.

[0060] As will be appreciated by those skilled in the art, the apparatus 10 can bedesigned and calibrated - for example by the design of the pre-determined shape of the sliding slot, by the size of the shoulder that can act as a piston face, the selection of the biasing member or combinations thereof - so that the apparatus 10 will engage when exposed to a predetermined flow rate and when engaged the apparatus 10 will automatically adjust the cross-sectional flow area of the second flow path (by adjusting the operational position) so that the actual flow rate does not exceed a predetermined maximal flow rate and so that the actual flow rate does not fall below a predetermined minimal flow rate.

[0061] FIG. 3 depicts a non-limiting example of the apparatus 10 in the firstoperational position and further comprising a tracer assembly 200 that is positionable within the mandrel 14, downstream of the sleeve 12. The assembly 200 comprises a tracer housing 202 that defines one or more tracer ports 204 and a tracer shift sleeve 203. The tracer housing 202 is held in a fixed position relative to the mandrel 14. The tracer ports 204 provide fluid communication between outside and inside of the tracer housing 202. The tracer housing 202 defines one or more tracer chambers. While FIG. 3 shows a tracer chamber 206 and a tracer chamber 208, the skilled person will readily understand that there may be more or less tracer chambers defined by the tracer housing 202. Within the tracer chambers 206, 208 a tracer, which may also be referred to as a pressure tracer, is retained.

[0062] FIG. 4 depicts the apparatus 10 of FIG. 3, in the second operationalposition. The forces that caused the sleeve 12 to shift downhole also cause the tracer shift sleeve 203 to shift downhole to a second tracer position. In the second tracer position, the tracer chamber 206 is in fluid communication with one or more of thetracer ports 204, which releases a first tracer from tracer chamber 206 into the fluid flowing through the apparatus 10.

[0063] The first tracer released from the tracer chamber 206 can then becaptured downhole from the apparatus 10 and analyzed to provide information to the operator of the geothermal system in which the apparatus 10 is deployed and retained in the desired position. For example, when captured and analyzed the first tracer can provide information about the differential pressure across the apparatus 10 caused by the fluid flowing through the apparatus 10. The information can be derived from a preset table that is based upon the known fluid pressure that will cause the apparatus 10 to move to the second tracer position and a specific property of the first tracer. In some embodiments of the present disclosure, each of the first tracers may be a specific chemical or chemical composition, whose signature is detectable / analyzable when the first tracer is captured downstream of the apparatus 10 by detecting an increased presence of the specific chemical / chemical composition. The apparatus 10 may house different tracers each being a different chemical in a different tracer chamber and each tracer chamber establishing fluid communication with one or more of the tracer ports 204 at a predetermined fluid pressure within the apparatus 10. In other embodiments of the present disclosure, each tracer may be a predetermined physical token that when released into the fluid may be captured downstream of the apparatus 10. Each token may convey pressure information by its shape, colour, information written thereupon or any combination thereof.

[0064] FIG. 5 depicts the apparatus 10 with the tracer shift sleeve 203 shiftedinto a third tracer position due to a change in the fluid pressure flowing through the apparatus 10. For example, in FIG. 5 the sleeve 12 is shown as having shifted further downhole relative to the mandrel 14, which in turn has cause the slot 24 to have a closed cross-sectional flow area through the second fluid path. In the third tracer position, the tracer chamber 208 is in fluid communication with one or more of the tracer ports 204 and the second tracer housed within the chamber 208 can move into the fluid flow for downstream capture and analysis so that the operator of the geothermal system will be able to derive information about the pressure of the fluid flowing through the apparatus 10.

[0065] FIG. 6 shows the apparatus 10 with a temperature monitoring assembly300 in the first temperature monitor position. The temperature monitoring assembly 300 comprises a temperature monitor mandrel 301 and a temperature monitor shift sleeve 305 positioned about the mandrel 301 with various seals 26 positioned therebetween to provide a fluid-tight arrangement between the mandrel 301 and the sleeve 305. The mandrel 301 defines one or more flow exit ports 303 that provide fluid communication from the flow path inside the apparatus 10 to outside the apparatus 10, downstream of the tracer assembly 200 so that a portion of the fluid that has passed through the tracer assembly 200 may then move outward from the apparatus 10 to pass in the space between the inner wall of the open hole 102 and the outer surface of the sleeve 300. This fluid path may be referred to herein as the third fluid path.

[0066] The outer surface of the mandrel 301 may define a shoulder that aportion of the sleeve 305 may contact so that the inner surface of the sleeve 305 is radially spaced from the outer surface of the mandrel 301 and the shoulder defines a first temperature monitor gas chamber 301A and a second temperature monitor gas chamber 301B. Each of the chambers 301A, 301B are fluid tight, due to the presence of various seals 26, as depicted in the non-limiting example of FIG. 6. The first chamber 301A contains a first gas and the second chamber 301B contains a second gas that is different than the first gas and, therefore, each gas has a different volumetric thermal expansion coefficient (VTEC). Therefore, when the fluid is flowing along the third fluid path, it will heat or cool each of the first and second gas and each gas will expand or contract but due to the different VTEC of each gas, the volume in the first chamber 301A and the second chamber 301B may change.

[0067] The sleeve 300 is held in a first position by a dissolvable holding pin308 that is positioned within a hole that extends through the sleeve 305 and mates with a depression defined on the outer surface of the mandrel 301. The dissolvable pin will dissolve when heated to a predetermined temperature, for example by the heated fluid flowing through the third fluid path.

[0068] The downhole end of the shift sleeve 305 may define one or more tracerchambers, shown as the non-limiting example of a first temperature monitor tracer chamber 302, a second temperature monitor tracer chamber 304 and a third temperature monitor tracer chamber 306. The skilled person will understand that the apparatus 10 may comprise more or less than three temperature monitor tracer chambers. Each chamber 302, 304, 306 houses a temperature tracer. When each chamber 302, 304, 306 are positioned above the mandrel 301, the tracers housed therein are retained within their respective chambers 302, 304, 306.

[0069] FIG. 7 shows the temperature monitoring assembly 300 with thedissolvable holding pin 308 dissolved and the temperature monitoring shift sleeve 305 shifted downhole to a second temperature monitor position. The volume of the second chamber 301B increasing a greater amount than the first chamber 301A caused the shifting sleeve 305 to shift downhole. In the second temperature monitor position, the chamber 302 is now no longer opposite the outer surface of the mandrel 301 and the tracer housed therein has been released into the fluid downstream of the apparatus 10. That temperature tracer can be captured and analyzed by an operator of the geothermal system. Akin to the pressure tracers described above, when captured and analyzed the temperature tracers provide information regarding the downhole fluid environment, such as the temperature of the fluid passing through the apparatus 10. Each temperature tracer may be a specific chemical, chemical composition, identifiable compound or gas, an engineered compound, or a predetermined physical token with identifiable characteristics, such as a unique radio frequency identification or the like.

[0070] FIG. 8 shows the temperature monitoring assembly 300 with thetemperature monitoring shift sleeve 305 shifted further downhole than as shown in FIG. 7 in a third temperature monitor position. The third temperature monitor position is due to the second gas in the chamber 301A having increased its volume (due to thermal expansion) greater than the first gas in the chamber 301B. In the third temperature monitor position, the chamber 304 has moved so that it is no longer opposite to the external surface of the mandrel 301 and a second temperature tracer has been released into the fluid downstream of the apparatus 10.

[0071] FIG. 9 shows the temperature monitoring assembly 300 with thetemperature monitoring shift sleeve 305 shifted further downhole than as shown in FIG. 8 in a fourth temperature monitor position. The fourth temperature monitor position is due to the second gas in the chamber 301A having further increased its volume (due to thermal expansion) to be greater than the first gas in the chamber 301B. In the fourth temperature monitor position, the chamber 306 has moved so that it is no longer opposite to the external surface of the mandrel 301 and a third temperature tracer has been released into the fluid downstream of the apparatus 10.

[0072] FIG. 10 shows another embodiment of the apparatus 10 that employs agroup of tracers to create a binary code to allow a user to determine a position of the temperature monitor shift sleeve. In the embodiment of FIG. 10, small incremental of movements of the shift sleeve can be determined with a fewer number of individual tracers the same tracer can be used for multiple positions (see FIG. 19). This embodiment comprises a hydraulic oil chamber 400 with a hydraulic oil release regulator 402 to slow the movement of the shift sleeve and space out the tracer readings at surface. The hydraulic oil release 402 regulator prevents sudden temperature changes or other shocks (such as when the dissolvable holding pin releases and the tool has cooled multiple shift sleeve positions) from releasing all the tracers at once and interfering with the ability to interpret the temperature readings at surface.

[0073] FIG. 11 and FIG. 12 show the apparatus 10 of FIG. 10 in furtherpositions so as to release a tracer (or pair of tracers) from further tracer chambers

[0074] FIG. 13 shows another apparatus 500 that, according to theembodiments of the present disclosure, can be used as an outflow control device that is configured to be deployed and retained inside a geothermal wellbore 600, where such wellbore is an injection geothermal well with casing 503 or other type of well that can utilize an outflow control device. The apparatus 500 can be deployed and retained proximal at least one outflow port 604 in the wall of the casing 503 and proximal an artificial, natural or human-made fracture 602 in the geologic formation in which the geothermal system is deployed so that fluid may exit the apparatus 500 and flow through the fracture 602 for capture by a geothermal wellbore at a distal endof the fracture 602 (as shown in FIG. 24). In some embodiments of the present disclosure, the apparatus 500 can be deployed with a setting tool to compress the external elements and slips. This embodiment may be suitable for plug and perforation style geothermal wells, among other types of wells. In other embodiments of the present disclosure, the apparatus 500 may be deployed and retained within a profile of a frac sleeve similar to a landing nipple (not shown). The apparatus 500 may further define external V-stack seals on the uphole and downhole ends of the apparatus 500 and a collet that will slide into the profile of the frac sleeve when unsupported and lock into the profile when supported. A system of dogs may be used to release the collet into the supported position, and then release the system from the supported position.

[0075] The apparatus 500 comprises one or more seals 516B, 516E between amandrel 501 and the casing 503 in order to fluidly isolate the fluid flow paths defined by the apparatus 500. The mandrel 501 defines two sets of fluid exit ports, a flow exit port 560 and pressure communication ports 580. These ports provide fluid communication between inside and outside of the mandrel 501. The mandrel can be retained in the desired location by one or more slip cones 516C, slips 516D, casing seals 516E and seal backups 516B that may be positioned about the outer surface of the mandrel 501 at the uphole end and the downhole end.

[0076] The apparatus 500 also comprises a shift sleeve 512 that may be in anested arrangement with a mandrel 501. The apparatus 500 further comprises a biasing member 515 that generates a biasing force to push the shift sleeve 512 in the uphole direction against a shift sleeve stopper 512A that extends outwardly from the outer surface of the mandrel 501. The shift sleeve 512 defines a first orifice 562 and a second orifice 563, both of which are configured to provide fluid communication from an inner surface of the shift sleeve 512 to an annular space between the apparatus 500 and the casing 503. The first orifice 562 may have substantially straight walls (i.e generally perpendicular to the longitudinal axis of the apparatus 500) or, optionally, the walls of the first orifice 562 may define a converging diverging portion so as to cause a pressure loss within the fluid flowing through the first fluid path. When the apparatus 500 is in a first operational position, the first orifice 562 is aligned with the flow exit port 560 of the mandrel 501. In this arrangement, the first orifice 562 and theport 560 define a first flow path for fluid to exit from inside the mandrel 501 to enter the annular space defined about the apparatus 500. When the apparatus is in the first operational position, the second orifice 563 is also aligned with the port 560 to define a second flow path for fluid to exit from inside the mandrel 501 to enter the annular space defined about the apparatus 500. The apparatus 500 further comprises a slot 524 that defines a triangular cross-sectional flow area through the second orifice 563.

[0077] As fluid is introduced into the geothermal injection wellbore, fluid willenters the uphole end of the mandrel 501, a small portion of the fluid will exit out the side of the tool, via the first and second flow paths, into the annular space and then through the outflow ports 604 into the fracture 602. The remainder of the fluid will continue to flow through the inside of the mandrel 501 and out the downhole end of the apparatus to zones further downstream in the geothermal injection well. As the fluid exits the apparatus 500 through the first and second fluid paths, a pressure drop occurs within the fluid within the mandrel 501. The pressure drop creates a pressure across the bottom portion of the shift sleeve 512 via the pressure communication ports 580. As the pressure drop increases, the pressure from the fluid flowing through the pressure communication ports 580 will drive the shift sleeve 512 in the downhole direction against the biasing force, which will compress the biasing member 515, further increasing the pressure drop (see FIG. 14) because the slot 524 also moves changing the cross-sectional flow area through the second flow path. This is referred to as the apparatus 500 being in the second operational position. The second operational position ensures that the actual flow rate does not increase too far past a desired target rate. (See FIG.26 for the intended flow rate vs pressure drop chart).

[0078] FIG. 15 shows the apparatus 500 in a third operational position, whichmay also be referred to as a shut off position. In the event that the flow rate out of the apparatus 500 by the first and second flow paths, increases to a pre-calibrated shut-off rate the shift sleeve 512 can shift further downhole and seal off the first and second flow paths. In these embodiments of the present disclosure, the shift sleeve 512 may also define a tracer chamber 590 that retains a tracer therein. In the third operational position, the tracer chamber 590 moved to a position past the seals 526 so that the tracer can be released into the fluid that is through the flow path to downstreamof the apparatus 500. The tracer can be captured and analyzed to provide information to the operator of the geothermal system that a particular apparatus 500 within the geothermal well system has a potential problem that resulted in an excessively high flow rate and, therefore, fluid flow into the fracture 602 has been shut off.

[0079] FIG. 16 shows an apparatus 700 that, according to the embodiments ofthe present disclosure, can be used as an inflow control device that is configured to be deployed and retained inside a geothermal wellbore 800, where such wellbore is a production geothermal well with casing 801 or other type of well that can utilize an inflow control device. The apparatus 700 can be deployed and retained proximal at least one inflow port 804 in the wall of the casing 801 and proximal an artificial, natural or human-made fracture 602 in the geologic formation in which the geothermal system is deployed so that fluid may enter the apparatus 700 from the fracture 602 (as shown in FIG. 24). The apparatus 700 may be deployed and retained at a desired position within the geothermal production wellbore 800 in a similar fashion as described above for the apparatus 500.

[0080] The apparatus 700 comprises one or more seals 716 between a mandrel701 and the casing 801 in order to fluidly isolate the fluid flow paths defined by the apparatus 700. The mandrel 701 defines three sets of fluid entry ports, a first flow entry port 760, which may also be referred to as a first orifice, a second port 780, which may also be referred to as a second orifice, and pressure communication ports 782. The second flow entry port 780 may have straight walls or it may define a converging and diverging flow path. These ports provide fluid communication between inside and outside of the mandrel 701 so that fluid entering the wellbore 800 from the fracture 802 may enter into the mandrel 701. The mandrel 701 can be retained in the desired location by one or more slip cones 716C, slips 716D, casing seals 716E and seal backups 716B that may be positioned about the outer surface of the mandrel 701 at the uphole end and the downhole end.

[0081] The apparatus 700 also comprises a shift sleeve 712 that may be in anested arrangement with the mandrel 701. The apparatus 700 further comprises a biasing member 715 within a housing 717 that is coupled to the external surface of theshift sleeve 712. The biasing member 715 that generates a biasing force to push the shift sleeve 712 in the downhole direction. The shift sleeve 712 defines an orifice 763, which is configured to provide fluid communication from the annular space about the apparatus 700 and inside the apparatus 700. The orifice 763 may retain an inflow slot 724B that defines a triangular shaped cross-sectional flow area within the orifice 763. The slot 724B may be retained within the orifice 763 by one or more retaining rings 720.

[0082] When the apparatus 700 is in a first operational position, the orifice 763is aligned with the port 760 of the mandrel 701. In this aligned arrangement, the orifice 763 and the port 760 define a first flow path for fluid to enter the apparatus 700 from the annular space defined about the apparatus 700. When the apparatus 700 is in the first operational position, the second port 780 defines a second flow path for fluid to enter the mandrel 701 from the annular space defined about the apparatus 700.

[0083] When fluid enters from the fracture 802, the fluid travels through thefirst and second flow paths to merge with the main flow of fluids that enter the apparatus and flow along its longitudinal axis. As the fluid passes through the first and second flow path, a pressure drop is created that creates a pressure differential across the shift sleeve 712. Rate limiting works in a similar fashion as in the apparatus 500. If the flow is reversed for any reason and flow is travelling out of the injection point and into the formation, the shift sleeve 712 will move in the opposite direction and completely shut off all orifices and fully shutoff the production point to prevent fluid losses (see FIG.28 for intended flow rate vs pressure drop).

[0084] FIG. 17 shows the apparatus 700 in a second operational position wherethe shift sleeve 7112 has shifted so that the inflow slot 724B has a reduced cross- sectional flow area, as compared to when the apparatus 700 is in the first operational position.

[0085] FIG. 18 shows the apparatus 700 in a third operational position wherethe shift sleeve 712 has moved to prevent inflow of fluid from the annular space about the apparatus 700 into the mandrel 701. In the third operational position, a tracerchamber 790 may be aligned with the orifice 763 so that a tracer can be released into the fluids within the apparatus 700 to be captured and analyzed by an operator of the geothermal well system. The tracer can provide information that the apparatus 700 has shut off inflow of fluids.

[0086] FIG. 19 shows a tracer housing 900 for establishing but one example ofa binary code generator where such binary code can be used to determine the position of a shift sleeve of any of the apparatus and systems described herein. for example, the housing 900 may comprise a plurality of tracer chambers (shown as 901 through 916 in FIG. 19), where a tracer as described herein above may or may not be releasably retained within a tracer chamber. A tracer chamber in a group that contains a tracer can be considered a “1” and a tracer chamber in a group that is empty can be considered a “0”. A possible configuration of the binary code for the figure in 7D could be as follows: Tracer 1: Chambers 901, 905, 909, 913 Tracer 2: Chambers 902, 906, 910, 914 Tracer 3: Chambers 903, 907, 911, 915 Tracer 4: Chambers 904, 908, 912, 916

[0087] Converting this to a binary code based on 4 groups the codes could be asfollows: Tracer group 1 position: “1111” – Tracers released from chambers 901, 902, 903, and 904 Tracer group 2 position: "0111” – Tracers released from chambers 906, 907, and 908, chamber 905 is empty Tracer group 3 position: “1011” -Tracer released from chambers 909, 911, and 912, chamber 910 is emptyTracer group 4 position: “1100” – Tracer released from chambers 913 and 914, chambers 915 and 916 are empty

[0088] As will be appreciated by those skilled in the art, such a binary code or asimilar binary code can be generated for all shifting sleeves that are present in a given apparatus or system of the present disclosure based upon a different number of tracer chambers or pattern of tracer chambers within the housing 900.

[0089] FIG. 20 shows a schematic of an example geothermal well system 1000with a multi-lateral injection well 1002 and a multi-lateral production well 1004 targeting the same naturally fractured formation in an open cycle conventional geothermal application. In this configuration, casing 1006 may be is installed, for example intermediate casing, at a depth above the target formation 1008 and the legs breakoff of each other to define two open hole sections 1010. As shown in FIG. 20, the target formation 1008 may include naturally created fractures 1009. Without flow control devices, it is unlikely that even flow distribution would result in either the injection well 1002 or the production well 1002. In this scenario, the estimated flow distribution could be as follows: Total Injection Rate: 5m3 / min Injector Leg 11012: ~1m3 / min Injector Leg 21014 : ~4m3 / min Producer Leg 11016: ~3.5m3 / min Producer Leg 21018: ~1.5m3 / min

[0090] FIG. 21 shows the same well system 1000 as FIG. 20, with an apparatus10 deployed and retained at a desired location within each wellbore 1002, 1004. With the apparatus 10 deployed as depicted the estimated flow distribution may shift to: Total Injection Rate: 5m3 / min Injector Leg 11012: ~2.5m3 / minInjector Leg 21014: ~2.5m3 / min Producer Leg 11016: ~2.5m3 / min Producer Leg 21018: ~2.5m3 / min Total Production Rate: 5m3 / min

[0091] With a more even flow distribution, due to the deployment of theapparatus 10 within each well 1002, 1004, the recoverable energy may be increased. The target formation 1008 may have a near-even thermal drawdown extending the life cycle of the geothermal well system 1000. The number of legs in this configuration is limited only by drilling technology and can eliminate the number of surface and intermediate casings required for exploitation of a large conventional geothermal system.

[0092] FIG. 22 shows a multi-lateral, closed-loop, closed cycle advancedgeothermal well system 1100 (with the upper panel depicting an isometric view and the lower panel showing a top plan view). In this configuration, fluid is pumped down an injection well 1102, split off into multiple legs 1105A, 1105B, 1105C, 1105D (similar to a heat sink) before rejoining into a production well 1104. Each well 1102, 1104 may be cased with intermediate casing 1106 to define an open-hole section 1110 therebelow with all the legs 1105A-1105D being within the open-hole section 1110. Without flow control devices, it is unlikely that even flow distribution would occur across all legs. Additionally, each leg added to the system provides diminishing returns making the flow distribution will become more uneven. This may lead to accelerated thermal drawdown in the high flow legs, reduced energy recovery and potentially shortened life cycle of the geothermal well system 1100. The flow rates in this scenario may be estimated to be: Total Injection Rate: 4m3 / min Leg 11105A: ~0.7m3 / min Leg 21105B: ~1.5m3 / minLeg 31105C: ~1.3m3 / min Leg 41105D: ~0.5m3 / min Total Production Rate: 4m3 / min

[0093] FIG. 23 shows a top plan view of the well configuration of the lowerpanel of FIG. 22, with flow control apparatuses 10, according to the present disclosure, deployed in each open-hole leg 1105A-1105D. The estimated flow distribution is now near even in all open-hole leg 1105A-1105D results in increased energy recovery and potentially extending the life cycle of the well system 1100. Additional legs can be drilled and have flow control devices 10 installed to eliminate the diminishing returns.

[0094] The flow rates in the scenario depicted in FIG. 22 may be estimated tobe: Total Injection Rate: 4m3 / min Leg 1: ~1m3 / min Leg 2: ~1m3 / min Leg 3: ~1m3 / min Leg 4: ~1m3 / min Total Production Rate: 4m3 / min

[0095] Fig. 24 shows an open cycle enhanced geothermal system 1200 in ahorizontal configuration. In this configuration fluid is pumped down an injection well 1202, the fluid travels through artificial fractures 1224, natural or human-made fractures in the geological formation 1008, and then enters a production well 1204. In the non-limiting example depicted in FIG. 24, each of the wells 1202, 1204 may have a surface portion, a heel and a toe. For example, the injection well 1202 may have a surface portion 1202A, a heel 1202B and a toe section 1202C and the production well 1204 may have a surface portion 1204A, a heel 1204B and a toe section 1204C. Eachof the wells 1202, 1204 be cased, for example with perforated casing and / or casing with fracturing ports that can open and close or they may have sections that are open-hole. When such casing is deployed, it may have a downhole terminus 1250 towards the toe and it may be held in place with the cement that is similarly perforated so there is fluid communication between the formation 1008 and each of the injection well 1202 and the production well 1204. The system 1200 may define multiple zones, each zone with an injection portion of the injection well 1202 and a producing portion of the production well 1204. The non-limiting example of system 1200 depicted in FIG. 24 comprises a first zone 1200A with an injection portion 1205A and a producing zone 1207A, a second zone 1200B with an injection portion 1205B and a producing zone 1207B, a third zone 1200C with an injection portion 1205C and a producing zone 1207C, a fourth zone 1200D with an injection portion 1205D and a producing zone 1207D and a fifth zone 1200E with an injection portion 1205E and a producing zone 1207E. As will be appreciated by those skilled in the art, the system 1200 may comprise more or less zones than are depicted in Fig. 24. In the scenario depicted in FIG. 24, the estimated flow distribution may be as follows: Total Injection Rate: ~5m3 / min First Zone 1200A Injection Rate in the injection portion 1205A: ~0.5m3 / min First Zone 1200A Production Rate in the producing portion 1207A: ~0.5m3 / min Second Zone 1200B Injection Rate in the injection portion 1205B: ~3.3m3 / min Second Zone 1200B Production Rate in the producing portion 1207B: ~3.3m3 / min Third Zone 1200C Injection Rate in the injection portion 1205C: ~0.1m3 / min Third Zone 1200C Production Rate in the producing portion 1207C: ~0.1m3 / min Fourth Zone 1200D Injection Rate in the injection portion 1205D: ~1m3 / min Fourth Zone 1200D Production Rate in the producing portion 1207D: ~-0.2m3 / min Fifth Zone 51200E Injection Rate in the portion 1205E: ~0.1m3 / minFifth Zone 1200E Production Rate in the production portion 1207E: ~0.1m3 / min Total Production Rate: ~3.8m3 / min

[0096] Enhanced geothermal faces the following known challenges that can bedemonstrated by this scenario:

[0097] Short-circuiting (also referred to as breakthrough or flow channeling) –when short-circuiting occurs, a large area flow path 1220 opens up between the injection well 1202 and the production well 1204. The result is a large percentage of the flow rate enters this flow path 1220 resulting in accelerated thermal drawdown in the short-circuited zone and significantly reduced well performance. This is shown in the second zone 1200B 2 where ~3.3m3 / min out of the total ~5m3 / min is entering the short- circuit flow path 1220.

[0098] Thief zones – thief zones typically occur when one or more naturalfractures 1222 cross between the injection well 1202 and the production well 1204. If the natural fracture is connected to a low pressure area of the formation 1008 then it will take fluids out of the open cycle system resulting in fluid losses. This is shown in the fourth zone 1200D where ~1m3 / min is entering the thief zone in the injection well 1202 and another ~0.2m3 / min is entering the thief zone from the production well resulting in ~1.2m3 / min being lost to the thief zone.

[0099] Heel dominance – with multiple zones, the further a zone is from theinjection or production point, the more fluid friction there is. Since the heels in both wells are closest to the injection point and production point, even without short- circuiting or thief zones present, there will be diminishing returns for each zone further from the heel. This is shown in this scenario where in the first zone 1200A is taking ~0.5m3 / min while the third zone 1200C and the fifth zone 1200E are only taking ~0.1m3 / min. This can result in accelerated thermal drawdown at the heel, reduced well performance, and potentially a shorter life cycle of the system 1200.

[0100] FIG. 25 shows the same well configuration as shown in FIG. 24, thistime with the apparatus 10, 500, 700 according to the embodiments of the presentdisclosure, deployed. With the apparatus 10 deployed, the estimated flow distribution may now be: Total Injection Rate: ~5m3 / min First zone 1200A Injection Rate in the injection portion 1205A: ~1.25m3 / min First zone 1200A Production Rate in the producing portion 1207A: ~1.25m3 / min Second zone 1200B Injection Rate in the injection portion 1205B: ~1.25m3 / min Second zone 1200B Production Rate in the producing portion 1207B: ~1.25m3 / min Third zone 1200C Injection Rate in the injection portion 1205C: ~1.25m3 / min Third zone 1200C Production Rate in the producing portion 1207C: ~1.25m3 / min Fourth zone 1200D Injection Rate in the injection portion 1205D: 0m3 / min Fourth zone 1200D Production Rate in the producing portion 1207D: 0m3 / min Fifth zone 1200E Injection Rate in the injection portion 1205E: ~1.25m3 / min Fifth zone 1200E Production Rate in the producing portion 1207E: ~1.25m3 / min Total Production Rate: ~5m3 / min

[0101] The challenges summarized in FIG. 24 may now be mitigated in thefollowing ways:

[0102] Short-circuiting – the outflow control devices 10 in the injection welland the inflow control devices in the production well limit the flow into the short- circuited section ensuring even flow distribution.

[0103] Thief zones – the outflow control device in the injection well hits acritical rate shutoff and prevents any flow from the injection well entering the thief zone. The inflow control device in the production well shuts itself off as result of the flow leaving the well into the thief zone instead of entering.

[0104] Heel dominance – The flow control devices installed at each zone ensurenear equal flow distribution in all zones.

[0105] With flow control devices installed, challenges to well performance havebeen mitigated, increasing the energy recovered and potentially extending the life cycle of the system. Additionally, large zone counts are possible without diminishing returns.

[0106] FIG. 26 is a line graph that depicts a theoretical pressure drop over flowrate through a flow control apparatus 10, 500, 700 according to the embodiments of the present disclosure, without a shut-off capability. Section A demarks the initial activation of the apparatus, section B demarks a target flow rate through the apparatus and section C demarks a flow rate where pressure drops increases at a lower rate than between sections B and C.

[0107] FIG. 27 is a line graph that depicts a theoretical pressure drop over flowrate through the apparatus 10, 500, 700, according to the embodiments of the present disclosure, with a shut-off capability. Section A demarks the initial activation of the apparatus, section B demarks a target flow rate through the apparatus and section C demarks a flow rate where pressure drops increases at a lower rate than between sections B and C. Section D demarks a shut-off flow rate where the pressure loss is maintained.

[0108] FIG. 28 is a line graph that depicts a theoretical pressure drop over flowrate through the apparatus 10, 500, 700 according to the embodiments of the present disclosure, with a reverse flow shut-off capability. Section A demarks the initial activation of the apparatus, section B demarks a target flow rate through the apparatus and section C demarks a flow rate where pressure drops increases at a lower rate than between sections B and C. Section D demarks a shut-off flow rate where the pressure loss is maintained.

[0109] FIG. 29 is a line graph that depicts a theoretical pressure drop over flowrate through a known flow control device. Section A demarks the initial activation of the apparatus, section B demarks a target flow rate through the apparatus and section C demarks a flow rate where pressure increases at a lower rate than betweensections B and C. Section D demarks a shut-off flow rate where the flow rate is reversed and the pressure loss continues to increase. As will be appreciated by those skilled in the art, absent the predetermined shape of the sliding slots of the apparatus 10, 500, 700, using a known flow control device may result in a similar graph to that shown in FIG. 29 where the flow rate drops significantly below the target flow rate after the device is engaged. Example

[0110] Non-limiting example of a design process for the predetermined shapeof sliding slot

[0111] Defined unit conversions:^ 1kPa = 0.145038psi^ 1m³ / min = 264.172gal / min^ 1mm = 0.0393701in^ 1mm² = 0.00155in²^ 1daN = 2.2481lbf^ 1kg / m³ = 0.0083454 lbm / gal

[0112] Initial Design Inputs:^ Piston Surface Area^ Target Initiation Pressure^ Target Initiation Flow Rate^ Target Maximum Pressure^ Target Maximum Flow Rate^ Shift Length^ Fluid density^ Coefficient of discharge

[0113] Initial Design Outputs:^ Spring Rate (based on shift length, piston force at target positions)^ Initial Spring Force (based on piston area and target initiation pressure)^ Initial Flow Area (based on target initiation pressure and flow rate)^ Final Flow Area (based on target maximum pressure and flow rate)^ Variable Flow Area (Initial Flow Area – Final Flow Area)

[0114] Incremental Breakdown^ Break shift length down to an incremental number of positions^ Set the target pressure drop at each incremental position such that position zerois the position with initial flow area and the maximum increment is the position with the maximum flow area. ^Calculate the flow area required to create the target pressure drop at eachincremental position ^Subtract the final flow area to calculate the incremental variable flow area^ Calculate the incremental flow area change from the previous position^ Define the previous increment as the top of a shape and the current increment asthe bottom, then use the incremental flow area to calculate the bottom length ^Summed together, all the incremental flow areas define a larger shape^ The shape is then modified and / or smoothed for optimal manufacturing

[0115] Calibration^ The calculated shape is tested in simulated conditions and the results are used toadjust the final shape to achieve the target flow regulation parameters

[0116] Table 1 - Example Calculation: InputsInputs Piston Area: 538.38 mm²Target Initiation Pressure: 138 kPaTarget Initiation Flow Rate: 0.042 m³ / minTarget Maximum Pressure: 689 kPaTarget Maximum Flow Rate: 0.045 m³ / minShift Length: 25.4 mmFluid Density: 1,000 kg / m³Coefficient of Discharge: 0.95 (unitless)

[0117] Table 2 - Initial Design OutputsInitial Design Outputs Spring Rate: 1.169 daN / mmInitial Spring Force: 7.4 daN[0 nsInitial Incremental CalculationsTarget Target Variable Increment Flow Pressu Stroke Piston Spring R t re Total Flow Flow Length Force Force eam² mm daN daN0 0.042 138 44.30 23.07 0.00 7.4 7.4 1 0.042 143 43.47 22.24 0.25 7.7 7.7 2 0.042 149 42.69 21.46 0.51 8.0 8.0 0.72 0.76 8.3 8.3 0.02 1.02 8.6 8.6 9.36 1.27 8.9 8.9 8.73 1.52 9.2 9.2 8.13 1.78 9.5 9.57.55 2.03 9.8 9.8 9 0.042 188 38.23 17.01 2.29 10.1 10.1 10 0.042 193 37.71 16.48 2.54 10.4 10.4 11 0.042 199 37.21 15.98 2.79 10.7 10.7 0 3 6 9 2 5 8 1 4 7 0 3 6 8 1 4 7 0 3 6 9 2 5 8 1 4 7 0 3 69 43 0.043 375 27.69 6.46 10.92 20.2 20.2 44 0.043 381 6.28 11.18 20.5 20.50.043 386 27.33 6.10 11.43 20.8 20.8 0.043 392 27.15 5.92 11.68 21.1 21.1 4 7 0 3 6 9 2 5 8 1 4 6 9 2 5 8 1 4 7 0 3 6 9 2 5 8 1 4 7 0 3 6 9 2 5 8 1 4 7 0 3 6 9 24 0.045 645 21.82 0.60 23.37 34.7 34.7 0.045 651 21.75 0.52 23.62 35.0 35.094 0.045 656 21.67 0.44 23.88 35.3 35.3 95 0.045 662 21.59 0.37 24.13 35.6 35.6 9 2 5 8 1[0In80.547 0.254 2.105 2.2069 0.523 0.254 2.017 2.10510 0501 0254 1929 201729 0.260 0.254 1.009 1.03530 0.252 0.254 1.0090.246 0.254 0.955 0.9790.239 0.254 0.927 0.9550.100 0.254 0.392 0.3960.099 0.254 0.39277 0.097 0.254 0.380 0.38378 0.096 0.254 0.372 0.380[0 y, the embodiments of thepr ll through which fluid can m e fluid in a dynamic and au rates within the well or a we paratus that has a mandrel an es (such as a side port) and the and the sliding sleeve are ph ow area is defined so thatwhen fluid is passing through the fluid path, it passes through the defined aperture. Due to changes in fluid flow rates, the operational position of the apparatus can change so that the physical alignment of the side port and the sliding slot changes. This change will change the first cross-sectional flow area to a second cross-sectional flow area. This change may be an increase or a decrease. When the first cross-sectional flow areais larger than the second cross-sectional flow area, a localized decrease in pressure loss will occur within the fluid being conducted through the second cross-sectional flow area. In contrast, when the first cross-sectional flow area is smaller than the second cross-sectional flow area, a localized increase in pressure loss will occur within the fluid being conducted through the second cross-sectional flow area. These localized changes in pressure loss occur automatically and result in mitigation of large fluctuations of flow rates through a well or well system that has such apparatus deployed therein.

Claims

I claim1. An apparatus for regulating a flow of fluids therethrough, the apparatuscomprising: (a) a retaining assembly for retaining the apparatus in a desired positionwithin a well; (b) a mandrel with a first end and a second end, defining a longitudinal axistherebetween, the mandrel defining one or more first set of orifices for fluid communication between inside the mandrel and outside the mandrel; (c) a shift sleeve in nested arrangement with the mandrel, the shift sleevedefining one or more second set of orifices for providing fluid communication between an inside of the shift sleeve and outside the shift sleeve, wherein the shift sleeve is shiftable in response to changes in one or more properties of a fluid flowing through the apparatus, wherein shifting of the shift sleeve changes a cross-sectional flow area of between the first set of orifices and the second set of orifices.

2. The apparatus of claim 1, further comprising one or more tracer chambers thateach retain a tracer that is releasable into the flow of fluids when the shift sleeve is at a predetermined position.

3. The apparatus of claim 1, wherein the mandrel, the shift sleeve or the apparatusis releasably retained in and retrievable from the well by one or more of wireline, a well tractor, coiled tubing, e-coil, jointed tubing, being threaded onto jointed tubing, being threaded onto casing or liner or any combination thereof.

4. The apparatus of claim 1, wherein the one or more properties of the fluidflowing through the apparatus are: pressure, a pressure differential across the apparatus, a flow rate or any combination thereof.

5. The apparatus of claim 1, wherein the well is used in an in-situ recoveryoperation, a mining operation, a solution mining operation, a carbon dioxide (CO2) injection operation, a water injection operation, a hydrocarbon recovery operation, or a geothermal well operation.

6. A well system comprising a wellbore with the apparatus of claim 1 deployedand retained at a desired position within a well of the well system.

7. The well system of claim 6, wherein the well system is used in an in-siturecovery operation, a mining operation, a solution mining operation, a carbon dioxide (CO2) injection operation, a water injection operation, a hydrocarbon recovery operation, or a geothermal well operation.

8. A method of regulating fluid flow through a well, the method comprising stepsof: (a) defining a fluid flow path for conducting fluid within the well;(b) changing a cross-sectional flow area of fluid flow path in response to achange in a change in one or more properties within the fluid; and (c) maintaining a fluid flow through the flow path at a desired flow rate.

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