Tool and method for choking fluid flow

Abstract

A downhole tool for choking flow of a fluid to be injected in a subsurface formation, has a choke having an annular choke body with fluid inlet and outlet ports and a choking medium disposed therebetween. The choking medium is deployed by a mechanical actuator for exposing the fluid inlet port to allow fluid flow through the choking medium.

Description

TOOL AND METHOD FOR CHOKING FLUID FLOWFIELD OF THE INVENTION

[0001] The present invention relates to the field of fluid injection to a subsurface formation and, in particular, to choking fluid during injection.BACKGROUND OF THE INVENTION

[0002] The increased demand for energy resulting from worldwide economic growth and development has contributed to an increase in concentration of greenhouse gases in the atmosphere. This has been regarded as one of the most important challenges facing humankind in the 21st century. To mitigate the effects of greenhouse gases (GHG), efforts have been made to reduce the global carbon footprint.

[0003] Efforts to mitigate the release of GHG have led to a variety of technologies for CCS (carbon capture and sequestration, or carbon capture and storage) and Negative Emission Technologies. With respect to geologic sequestration, efforts have predominantly been directed towards injecting gaseous or supercritical - close to pure - CO2 into a subsurface formation.

[0004] The use of depleted hydrocarbon reservoirs has been considered for CO2 storage. One challenge for injecting the CO2 into the depleted reservoir is related to CO2 phase behaviour. Expansion or evaporation of the CO2 may lead to extremely low temperatures in the well, posing limitations on well design, integrity, and operability, and injectivity as hydrates may form. Alternatively, in case of a strong aquifer, water backfills the porous formation after the hydrocarbons are produced from the reservoir. Accordingly, a significant pressure is required for injecting CO2 to overcome the water pressure in the formation and limited capacity is available for storage without potential risking caprock integrity. Compression of the gas requires energy, potentially with a related GHG footprint.

[0005] Another challenge facing the injection of CO2 is the structure of the subsurface formation. Even dense phase CO2 is light i.e., less dense than water, and will naturally travel upwardly in the formation because of buoyancy. Therefore, the formation should have a high- quality seal to avoid leak paths that could result in release into the environment. When u w ard mobility is limited, CO2 will then migrate laterally potentially encountering additional leaks paths related to lack of closure, faults, or improperly abandoned w ells. This presents limitations of where CO2 can be responsibly injected and necessitates extensive CO2 monitoring activities for a prolonged period to ensure the CO2 remains in the subsurface formation.

[0006] Similar challenges face efforts to inject hydrogen and other fluids into depleted reservoirs.

[0007] Efforts to address the challenges of CO2 injection include the tools used to inject the fluid into the subsurface.

[0008] For example, Cawley et al. (US9163489, 20 Oct 2015; EP2406460B1, 11 Nov 2015) describes a method and system for injecting CO2 into an aquifer or a depleted hydrocarbon reservoir using a fluid injection control valve that closes when the pressure above the valve is less than a pre-set pressure and opens when the pressure opens when the pressure above the valve is greater than or equal to the pre-set pressure. The pre-set pressure is selected to maintain the CO2 in a liquid or supercritical state. The fluid control valve has an actuating means that provides a biasing force to the valve closure element.

[0009] Another example is Fripp et al. (US2022 / 0333460A1, 20 Oct 2022; WO2022 / 221790A1, 20 Oct 2022) relates to a downhole vapor-transition control valve for fluid inj ection. The fluid control valve has a chamber with a variable volume and filled with a fill fluid comprising CO2 or an azeotrope of CO2. The chamber includes a biasing device to apply a biasing force to reduce the pressure level in fill fluid. The biasing device may be a bellows that enclose the chamber and fill fluid, or a spring positioned in the chamber.

[0010] In the Cawley et al. and Fripp et al. devices, the flow control valves are responsive to pressures in the injection tubing to cause opening or closing based on a pressure measurement in efforts to maintain the CO2 fluid in a dense phase. As such, the choking of fluid flow is concentrated at the valve itself, creating a higher risk for erosion by the fluid. As the flow control valves are eroded, the risk of fluid leaks and valve failure increases.

[0011] Alternatively, a conventional wireline conveyed plug with choke functionality can be used to choke the injected fluid downhole. A disadvantage of this approach is that intervention is required to change the amount of choking provided by the plug. Specifically, the plug must be pulled to surface and replaced with a choke plug with a reduced pressure drop, requiring a well intervention for each choke change out. Each intervention is associated with operational downtime and the associated cost thereof.

[0012] In another conventional approach, a series of shrouded inflow' control valves may be provided with internal diverted plugs / fixed chokes. A disadvantage of this approach is that is not designed for controlled choking of CO2 flow. Also, it does not overcome the disadvantage of the Caw ley et al. and Fripp et al. devices discussed above.

[0013] There remains a need for improved tools and methods for injecting CO2 and other fluids, especially fluids subject to phase change behaviour at injection conditions.SUMMARY OF THE INVENTION

[0014] According to one aspect of the present invention, there is provided a downhole tool for choking flow of a fluid to be injected in a subsurface formation, the downhole tool comprising: a choke having an annular choke body having an internal w all defining an annular tube and an external wall, the internal wall having a fluid inlet port proximate an upper end of the choke body, the choke body having a fluid outlet port proximate a lower end of the choke body; a choking medium disposed within the choke body; an inner sleeve coaxially mounted within the annular tube, the inner sleeve mounted in a closed position with a shear pin such that the inner sleeve covers the fluid inlet port; the inner sleeve provided with a landing seat defining a pass-through diameter less than an internal diameter of the inner sleeve; and a sleeve seat provided on an inner surface of the internal wall of the choke body; and a mechanical actuator having a maximum outer diameter less than the inner diameter of the inner sleeve and greater than the pass-through diameter, the mechanical actuator causing the shear pin to shear when the mechanical actuator engages the seat, thereby causing the inner sleeve to slidably move from the closed position to an open position where the inner sleeve exposes the fluid inlet port for fluid flow' through the choking medium and the inner sleeve rests on the sleeve seat.

[0015] According to another aspect of the present invention, there is provided a method for injecting a fluid from a surface into a target formation, the method comprising: providing a tubing string in a casing to provide an open-hole annulus between the injection tubing and the casing, wherein a portion of the open-hole annulus in a region of the target formation is fluidly isolated from the surface w ith a production packer; providing the tubing string with at least tw o chokes, w herein a first of the at least tw o chokes is located upstream of a second of the at least two chokes, wherein each of the at least two chokes has a choking medium; controlling at least one of pressure and flowrate of the fluid into the target formation by selectively opening a flow path in one or more of the at least two chokes; wherein the flow path is selectively opened by a mechanical actuator.BRIEF DESCRIPTION OF THE DRAWINGS

[0016] The process of the present invention will be better understood by referring to the following detailed description of preferred embodiments and the drawings referenced therein, in which:

[0017] Figs. 1, 2 and 3 are cross-sectional views of embodiments of the downhole tool of the present invention;

[0018] Figs. 4A - 4C, 5, 6A - 6B and 7 are cross-sectional views of embodiments for deploying the downhole tool of the present invention; and

[0019] Figs. 8A - 8B and 9A - 9B are cross-sectional views of other embodiments of the downhole tool of the present invention.DETAILED DESCRIPTION OF THE INVENTION

[0020] The present invention provides a downhole tool and a method for choking flow of a fluid to be injected in a subsurface formation. The downhole tool has a choke and a mechanical actuator to cooperatively allow the injected fluid to flow into the formation.

[0021] The present invention addresses shortcomings of conventional techniques by choking fluid flow without the need for a spring-loaded valve. Further, the choking configuration can be controlled from surface without intervention. The downhole tool and method are suitable for the injection of fluids that undergo phase change during injection, such as for example, without limitation. CCh and H2

[0022] The downhole tool and method of the present invention are particularly suitable for Carbon Capture and Storage (CCS) projects, where CO2 is injected into depleted stores. Such depleted stores can be oil or gas reservoirs that are no longer economically viable for production. The purpose of this invention is to choke the flow of CO2, keeping the CO2 in dense phase within the tubing during CO2 injection. Without the dowiihole tool and method of the present invention to choke fluid flow to provide, the needed pressure drop would not be applied and, therefore, the fluid, such as CO2, will convert into the gas phase, resulting in uncontrolled cooling of the well caused by evaporation, expansion due to the Joule-Thompson effect, and / or subject the reservoir formation to an extreme pressure, which may cause damage due to the creation of fractures. This invention provides a choke to fluid flow that can be fully integrated into the lower completion of a CCS well.

[0023] Referring now to the drawings. Figs. 1, 2 and 3 are cross-sectional views of embodiments of the downhole tool 10 of the present invention. The downhole tool 10 has a choke 12 and a mechanical actuator 14. The choke 12 has an annular choke body having an internal wall 16 defining an annular tube and an external wall 18. A choking medium 20 is disposed within the choke body. The internal wall 16 has a fluid inlet port 22 proximate an upper end of the choke body. A fluid outlet port 24 is located proximate a lower end of the choke body.

[0024] An inner sleeve 26 is coaxially mounted within the annular tube. In Figs. 1, 2 and 3, the inner sleeve 26 is mounted in a closed position with a shear pin 28 such that the inner sleeve 26 blocks fluid flow the fluid inlet port 22. The inner sleeve 26 has a landing seat 32 defining a pass-through diameter, 0, less than an internal diameter of the inner sleeve 26. The landing seat 32 is preferably placed as shown in Fig. 1 proximate a lower end of the inner sleeve 26 to reduce the risk of the inner sleeve 26 and / or internal wall 16 collapsing under a pressure differential over the length of the choking medium 20. Alternatively, or in addition, the inner sleeve 26 and / or internal w all 16 may be formed w ith a sufficiently thick wall thickness to avoid collapse. A sleeve seat 34 is provided on an inner surface of the internal wall 16 of the choke body 12. In the embodiments of Figs. 1 and 2, the fluid outlet port 24 is located proximate a lower end of the external wall 18 of the choke 12.

[0025] The mechanical actuator 14 has a maximum outer diameter less than the inner diameter of the inner sleeve 26 and greater than the pass-through diameter, 0. The mechanical actuator 14 causes the shear pin 28 to shear when the mechanical actuator 14 engages the landing seat 32 of the inner sleeve 26. When the mechanical actuator 14 engages the landing seat 32, a pressure differential is provided by the fluid being inj ected, which causes the shear pin 28 to shear. It will be understood by those skilled in the art that the shear pin 28 can be selected to shear at a predetermined pressure. The mechanical actuator 14 and landing seat 32 can be provided with cooperating mechanisms to latch the mechanical actuator 14 to the landing seat 32 to avoid upward displacement in the event of fluid back -flow and / or reverse flow through the tubing. As will be discussed further herein with respect to operation of the downhole tool 10, downward movement of inner sleeve 26 is restricted by the sleeve seat 34.

[0026] In the embodiment of Fig. 1, the mechanical actuator 14 is a dart. In the embodiment illustrated in Fig. 2. the mechanical actuator 14 is a ball.

[0027] The embodiment of Fig. 3 provides an alternative fluid flow path through the choke 12. The fluid outlet port 24 is located proximate a lower end of the internal wall 16 of the choke 12 to allow fluid to vent to the tubing annulus 68.

[0028] The choking medium 20 is provided to choke fluid flow through the choke body when the fluid inlet port 22 is open to fluid flow. The choking medium may be, for example, without limitation, packing material, tubing defining a spiral fluid flow path, corrugations integrated into choke body defining a spiral or other tortuous fluid flow path, and combinations thereof. As discussed below, the choking medium 20 may be integral with and / or added to the choke body. The choking medium 20 is preferably disposed between the fluid inlet port 22 and the fluid outlet port 24. Depending on the nature of the choking medium 20 used, the choking medium 20 may be positioned and or defined in the choke body, for example, in an encasement or with a flange 36. The flange 36 is provided with openings that further provide a tortuous path for fluid flow.

[0029] The amount and / or tortuosity of choking medium 20 is selected to provide a suitable pressure drop of fluid flowing therethrough.

[0030] In the case where the choking medium 20 is a packing material, the packing material is preferably formed from a wear-resistant material for high-temperature, oxidation, and / or chemical resistance. An example of a suitable material is a ceramic, such as silicon nitride. The packing may be in the form of spheres, rings, and the like. A packing material may also be provided in the form of stacked discs arranged to create a tortuous fluid flow' path by limiting flow through certain portions of a disc and / or rotating openings in the discs to form a labyrinth. The option of packing material as choking medium 20 is depicted in Fig. 1.

[0031] In the embodiment where the choking medium 20 is provided by corrugations, the exterior of the internal wall 16 and / or the interior surface of the external wall 18 may be machined with a rough and / or tortuous pattern to increase friction, as compared with a smooth wall. Alternatively, a cylindrical hollow body may have interior surfaces machined with a rough and / or tortuous pattern to increase fraction. The option of corrugation as choking medium is depicted is Fig. 2.

[0032] The corrugation of Fig. 2 may be supplemented, in whole or in part, with a packing material, such as spheres, provided in the interstitial spaces of the corrugations.

[0033] In the embodiment where the choking medium 20 is a tubing, the tubing may be rapped around the internal wall 16 or the tubing may be integral in the body of the internalwall 16 and / or the external wall 18 with machined channels on one or both surfaces. Alternatively, a cylindrical hollow body may have machined channels on the interior surface thereof. The tubing may have a uniform internal diameter throughout the length of the choking medium 20. Alternatively, the tubing may have a change in internal diameter along the length thereof. For example, the tubing may have a smaller internal diameter closer to the fluid outlet port 24, as compared with the internal diameter closer to the fluid inlet port 22. The option of tubing as choking medium is depicted is Fig. 3.

[0034] The tubing of Fig. 3 may be supplemented, in whole or in part, with a packing material, such as spheres, provided in the interstitial spaces of the tubing. An advantage of the embodiment of Fig. 3 is that vibrations caused by choked fluid passing through the choking medium 20 are reduced.

[0035] In the embodiment of Fig. 2, the choke body is provided with a non-retum valve 38 in an opening in the flange 36 upstream of the fluid outlet port 24. The non-retum valve 38 may alternatively be provided at the fluid inlet port 22 to reduce fluid velocity and / or erosion risk. The purpose of the non-retum valve 38 is to avoid back flow from the open hole annulus 62 into the choke body and tubing string when injection of fluid is stopped. By controlling the flow of fluid back into the choke body, the formation of deleterious pressure waves is reduced. Another purpose of the non-retum valve 38 is to reduce migration of fines, such as small sand particles, from the formation back into the tubing annulus 10, thereby avoiding fill or plugging of the choking medium 20 when backflow occurs. The option of providing the non-retum valve 38 is particularly useful for embodiments wherein the fluid outlet port 24 vents to open hole annulus 62. In the embodiment of Fig. 3, back flow control may be provided by a non-retum valve in the bullnose 66, as discussed hereinbelow.

[0036] The options provided for the choking medium 20 described above may be formed as a monolithic structure with a porosity formed by chemical etching or by 3D printing.

[0037] The choking medium encasement or flange 36 may be provided with a nozzle or a diffuser to supplement the fluid choking. In the case of a tubing option (Fig. 3), the outlet of the tubing may be provided with additional tubing fitted to the fluid outlet port 24.

[0038] Figs. 4A, 4B and 4C illustrate one embodiment for deploying the downhole tool 10 of the present invention. Figs. 4A. 4B and 4C are schematic drawings of an integrated completion system using three chokes 12. 1, 12.2, 12.3 in a pre-drilled section. The actual number of chokes 12 used can be tailored the specific deployment. Preferably, two or more chokes 12 willbe used. By using two or more chokes, it is possible to change the degree of fluid-choking without the need for intervention. Additional chokes 12 may be provided. Alternatively, the degree of choking may be selected so that following the second choke 12, the reservoir pressure is sufficient to maintain the injection fluid in a dense phase, thereby no further choking may be required. For clarity, the drawing only shows a partial and simplified completion that would typically comprise other downhole equipment. Further, the chokes 12.1, 12.2, 12.3 are depicted as being integral w ith the tubing string. Preferably, the chokes 12.1. 12.2, 12.3 are connected with lengths of tubing string in the same manner as conventional tubing string lengths are connected to one another. Additionally, reference numerals for elements of the chokes 12 are not provided in Figs. 4A, 4B and 4C. The reader is asked to refer to Figs. 1, 2 and 3 that provide more detail for the choke 12 and the reference numerals therefor.

[0039] A tubing string 52 is landed and positioned inside a production casing 54. which is typically anchored and sealed on the backside with cement 56 and installed across impermeable formation 58. Tubing string 52 further extends into an open hole annulus 62 across permeable formation 64 (e.g., depleted reservoir), which is the target formation to inject fluid, such as CO2. The bottom of the tubing string 52 may include a bullnose 66 with a non-retum-valve to separate the tubing annulus 66 from the open hole annulus 62 and to allow fluid to flow from the tubing annulus 68 into the open hole annulus 62. The open hole annulus 62 is isolated with a production packer 72, preventing the injected fluid from flowing to surface.

[0040] Each choke 12.1, 12.2, 12.3 is configured for a change in pressure drop with depth by increasing the amount of choking medium 20. The deepest choke 12.1 provides the highest pressure drop, while the shallowest choke 12.3 provides the least pressure drop.

[0041] As shown in Fig. 4A, all chokes 12.1, 12.2, 12.3 are initially closed and there is no circulation of fluid through the chokes from the tubing annulus 68 into the open-hole annulus 62.

[0042] Fig. 4B illustrates that the bottom choke 12.1 was opened with mechanical actuator 14. The pass-through diameter. 0, is larger at chokes 12.2 and 12.3 to allow the mechanical actuator to pass through to choke 12. 1. When the mechanical actuator 14 reached choke 12.1, the mechanical actuator 14 engaged the landing seat 32 of choke 12.1, causing shear pin 28 to shear and the inner sleeve 26 to travel downward to rest on the sleeve seat 34. This action allows the injected fluid to pass through the fluid inlet port 22 of choke 12. 1 as depicted by the arrows in Fig. 4B.

[0043] The inj ected fluid passes through the choking medium 20 of choke 12.1 to the fluid outlet port 24. The choking medium 20 provides that the injected fluid remains in liquid phase inside the tubing annulus 68 above the activated choke 12 during injection. When the injected fluid passes through the choking medium 20. the phase may change to gas phase or supercritical phase, depending in the reservoir pressure. As shown in Fig. 4B, the injected fluid flows through the fluid outlet port 24 to the tubing annulus 68 and through bullnose 66 to the permeable formation 64.

[0044] In the early stages of injection, the permeable formation 64 requires the lowest pressure drop as injected fluid slowly increases the reservoir pressure. As the reservoir pressure increases, the fluid can be safely injected at higher pressures and higher flow rates. To allow for more injection volume whilst keeping the fluid in dense phase in tubing 52, less fluid choke is required. Accordingly, a shallower choke 12.2 is then opened. Injection rate increases w ith less choking medium 20 in the shallower choke 12.2. This provides sufficient pressure drop to maintain the fluid inside the tubing 52 in liquid / dense phase.

[0045] Fig. 4C illustrates operation where all three chokes 12.1, 12.2, 12,3 are opened as lower pressure drop is required. Additional mechanical actuators 14 are dropped downhole to engage first the landing seat 32 of choke 12.2 and later the landing seat 32 of choke 12.3 to shear the respective shear pins 28 to allow injected fluid to flow through the respective choking medium 20. In the embodiment of Fig. 4C, choke 12.3 redirects the fluid flow from the tubing annulus 68 through fluid outlet port 24 of choke 12.3 into open hole annulus 62 into the permeable formation 64. as depicted by arrows in Fig. 4C.

[0046] A cemented downhole completion with a cemented bottom hole 74 is illustrated in Fig. 5. Injected fluid flows from the tubing annulus 68 below the deepest choke 12.1 into the permeable formation 64 via perforations 76. As illustrated by the arrows in Fig. 5, injected fluid travels from the tubing annulus above choke 12.3 through the choking medium 20 of choke 12.3 through the open hole annulus 62 and back into the tubing annulus 68 through tubing perforations. The injected fluid then flows via the perforations 76. Such perforations may be provided by perforations in the tubing string 52 or by a conventional sliding side door, as will be understood by those skilled in the art of well completion.

[0047] Figs. 6A and 6B provide a schematic overview of another embodiment for deploying the present invention. In this embodiment, the downhole tool 10 is deployed as part of a drill-in liner system. Instead of bullnose 66 (as shown in Figs. 4A-4C and 5), a sacrificialdrilling Bottom Hole Assembly (BHA) 78 is used. Preferably, a wash-pipe 82 is used to circulate the drilling fluid and runs from the liner top downhole to the drilling BHA 78. Where a wash pipe 82 is used, it is provided to reduce the impact of erosion on completion equipment caused by circulation of solids. In an alternate embodiment, the wash-pipe 82 is not used and the completion equipment is made from wear-resistant materials.

[0048] As depicted by arrows in Fig. 6 A, drilling fluid is circulated to the BHA 78, optionally through the wash-pipe 82, and drill cuttings are returned to surface. The drill-in liner system with chokes 12.1, 12.2, 12.3 can be rotated for drilling.

[0049] Referring now to Fig. 6B, once drilling is completed to a target depth, the production packer 72 is activated. The sacrificial drilling BHA 78 is left downhole. An advantage of incorporating the downhole tool 10 in a drill-in liner system is that drilling into depleted formation requires often drill-in liners in view of borehole stability issues and severe drilling fluid losses into the permeable formation 64. The chokes 12. 1, 12.2, 12.3 are activated are discussed above with respect to Figs. 4A - 4C.

[0050] In one embodiment, the mechanical actuator 14 is equipped with a sensor (not shown), advantageously with a power source such as a battery, for recording downhole conditions, such as pressure and temperature, of interest in determining and / or modifying a fluid injection scheme. The data could also be used for diagnostic purposes. The data may be transmitted to surface in a manner known to those skilled in the art. Alternatively, the mechanical actuator 14 may be retrieved to surface on wireline to read data.

[0051] Fig. 7 illustrates another embodiment where the mechanical actuator 14 can be used to deploy an optical fibre 84 into the well as the mechanical actuator 14 is dropped downhole to allow a short-term survey to be made, for example, while the well is in a low- or no-flow injection regime. Fig. 7 illustrates the ability to perform logging operations whilst injecting.

[0052] Figs. 8A - 8B illustrate another embodiment of the downhole tool 10 of the present invention. The choke 12 is provide with a choke bypass 85. In normal operation, illustrated in Fig. 8A, the choke bypass 85 is blocked with a pressure relief mechanism. As discussed hereinabove, once the mechanical actuator 14 lands on the landing seat 32, the shear pin 28 shears, thereby allowing the inner sleeve 26 to slidably move downwardly to the sleeve seat 34. This allows injected fluid to access the fluid inlet port 22. The injected fluid flows through the fluid inlet port 22 through the choking medium 20 and out the fluid outlet port 24.

[0053] In a further embodiment, a spring (not shown) may be placed between the bottom edge of the inner sleeve 26 and the sleeve seat 34 to close the inner sleeve 26 autonomously when fluid injection has stopped.

[0054] Fig. 8B depicts the formation of an undesirable blockage 90 inhibiting fluid flow through the choking medium 20, having the undesired effect of creating a pressure build-up. The increased pressure activates the pressure relief mechanism in the choke bypass 85 to open fluid flow7through choke bypass 85.

[0055] Figs. 9A - 9B illustrate another embodiment of the downhole tool 10 of the present invention. The mechanical actuator is provided with an actuator bypass 86. In normal operation, illustrated in Fig. 9A, the actuator bypass 86 is blocked with an actuator pressure relief mechanism 88. The tubing is further provided with a tubing pressure relief mechanism 89. As discussed hereinabove, once the mechanical actuator 14 lands on the landing seat 32, the shear pin 28 shears, thereby allowing the inner sleeve 26 to slidably move downwardly to the sleeve seat 34. This allows injected fluid to access the fluid inlet port 22. The injected fluid flow s through the fluid inlet port 22 through the choking medium 20 and out the fluid outlet port 24.

[0056] Fig. 9B depicts the formation of an undesirable blockage 90 inhibiting fluid flow through the choking medium 20, having the undesired effect of creating a pressure build-up. The increased pressure activates the pressure relief mechanism 88 to open fluid How through actuator bypass 86. The change in fluid pressure below7the mechanical actuator 14 triggers the tubing pressure relief mechanism 89 to open passage for fluid flow from the tubing annulus 68. An advantage to the embodiment of Figs. 9A - 9B, over the embodiment is that the pressure relief mechanism 88 provides an alternative or additional means of choking fluid flow.

[0057] The drawings depict different embodiments of certain elements of the invention. It should be understood that pairings of one embodiment of an element is not necessarily limited to an embodiment of another element in the same drawing.

[0058] While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions, and improvements are possible. Various combinations of the techniques provided herein may be used.

Claims

CLAIMS1. A downhole tool for choking flow of a fluid to be injected in a subsurface formation, the downhole tool comprising: a choke having an annular choke body having an internal wall defining an annular tube and an external wall, the internal wall having a fluid inlet port proximate an upper end of the choke body, the choke body having a fluid outlet port proximate a lower end of the choke body; a choking medium disposed within the choke body; an inner sleeve coaxially mounted within the annular tube, the inner sleeve mounted in a closed position with a shear pin such that the inner sleeve covers the fluid inlet port; the inner sleeve provided with a landing seat defining a pass-through diameter less than an internal diameter of the inner sleeve; and a sleeve seat provided on an inner surface of the internal wall of the choke body; and a mechanical actuator having a maximum outer diameter less than the inner diameter of the inner sleeve and greater than the pass-through diameter, the mechanical actuator causing the shear pin to shear when the mechanical actuator engages the seat, thereby causing the inner sleeve to slidably move from the closed position to an open position where the inner sleeve exposes the fluid inlet port for fluid flow through the choking medium and the inner sleeve rests on the sleeve seat.

2. The downhole tool of claim 1, wherein the choking medium is selected from the group consisting of packing material, tubing defining a spiral fluid flow path, corrugations integrated into choke body defining a spiral or other tortuous fluid flow path, and combinations thereof.

3. The downhole tool of claim 1, wherein the choking medium is integrated in an interior surface of the outer body.

4. The downhole tool of claim 3, wherein the choking medium is selected from the group consisting of corrugations, channels, and combinations thereof.

5. The downhole tool of claim 1, wherein the fluid outlet port is provided in the external wall of the choke body.

6. The downhole tool of claim 1, wherein the fluid outlet port is provided in an internal wall of the choke body, below the sleeve seat.

7. The downhole tool of claim 1, wherein the choke further comprises a non-retum valve.

8. The downhole tool of claim 1, wherein the choke is provided in a tubing string.

9. The downhole tool of claim 8, wherein tubing string is provided with at least two chokes, wherein a first of the at least two chokes is located upstream of a second of the at least two chokes.

10. The downhole tool of claim 9, wherein the second of the at least two chokes is configured to provide a higher pressure drop to the fluid than the first of the at least two chokes.

11. The downhole tool of claim 1, wherein the mechanical actuator is a dart having an elongated body with a radial shoulder having a diameter to engage the seat.

12. The downhole tool of claim 1, wherein the mechanical actuator is provided with a pressure release mechanism to allow fluid flow through the dart when the choking medium is plugged.

13. The downhole tool of claim 8, wherein the tubing string comprises a bullnose with a non-retum valve.

14. The downhole tool of claim 8, wherein the tubing string comprises a bottom hole assembly.

15. A method for injecting a fluid from a surface into a target formation, the method comprising:providing a tubing string in a casing to provide an open-hole annulus between the injection tubing and the casing, wherein a portion of the open-hole annulus in a region of the target formation is fluidly isolated from the surface with a production packer; providing the tubing string with at least two chokes, wherein a first of the at least two chokes is located upstream of a second of the at least two chokes, wherein each of the at least two chokes has a choking medium; controlling at least one of pressure and flowrate of the fluid into the target formation by selectively opening a flow path in one or more of the at least two chokes; wherein the flow path is selectively opened by a mechanical actuator.

16. The method of claim 15, wherein the fluid is CO2.

17. The method of claim 15, wherein the second of the at least two chokes is configured to provide a higher pressure drop to the fluid than the first of the at least two chokes.

18. The method of claim 15, wherein the target formation is a reservoir depleted in oil or gas.

19. The method of claim 15, wherein the tubing string comprises a bullnose with a nonreturn valve for allowing flow from the injection tubing to the open-hole annulus.

20. The method of claim 15, wherein the tubing string comprises a bottom hole assembly, and, prior to the step of providing the fluid, further comprising the steps of drilling an injection well with the bottom hole assembly; and activating the production packer.

21. The method of claim 15, wherein a choke having an annular choke body having an internal wall defining an annular tube and an external wall, the internal wall having a fluid inlet port proximate an upper end of the choke body, the choke body having a fluid outlet port proximate a lower end of the choke body; and the choking medium is disposed within the choke body.

22. The method of claim 21, wherein the choke further comprises an inner sleeve coaxially mounted within the annular tube, the inner sleeve mounted in a closed position with a shear pin such that the inner sleeve covers the fluid inlet port; the innersleeve provided with a landing seat defining a pass-through diameter less than an internal diameter of the inner sleeve, and a sleeve seat provided on an inner surface of the internal wall of the choke body.

23. The method of claim 22, wherein the mechanical actuator has a maximum outer diameter less than the inner diameter of the inner sleeve and greater than the pass- through diameter, the mechanical actuator having a weight sufficient to shear the shear pin when the mechanical actuator engages the seat, thereby causing the inner sleeve to slidably move from the closed position to an open position where the inner sleeve exposes the fluid inlet port for fluid flow through the choking medium and the inner sleeve rests on the sleeve seat.

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