WO2026010768A1

WO2026010768A1 - Liner with removable injection check valve plugs

Info

Publication number: WO2026010768A1
Application number: PCT/US2025/034969
Authority: WO
Inventors: Federico A. Tavarez; Richard F. MOLLOY
Original assignee: ExxonMobil Technology and Engineering Co
Current assignee: ExxonMobil Technology and Engineering Co
Priority date: 2024-07-03
Filing date: 2025-06-24
Publication date: 2026-01-08
Anticipated expiration: 2027-01-03

Abstract

Techniques described herein relate to a well completion assembly including a liner (102) extending into a reservoir. The liner includes a number of plugged injection check valves (104A-104C) arranged along the liner into a number of sets corresponding to a number of zones of the reservoir. The liner is configured to inject fluid into the number of zones of the reservoir.

Description

LINER WITH REMOVABLE INJECTION CHECK VALVE PLUGS CROSS-REFERENCE TO RELATED APPLICATION [0001] This application claims priority to and the benefit of U.S. Provisional Application No. 63/667,360, entitled “LINER WITH REMOVABLE INJECTION CHECK VALVE PLUGS,” having a filing date of July 3, 2025, the disclosure of which is incorporated herein by reference in its entirety. FIELD [0002] The techniques described herein relate to the field of well completions and downhole operations. More particularly, the techniques described herein relate to a liner, which may be used, for example, for carbon sequestration, water injection, or reservoir stimulation. BACKGROUND [0003] This section is intended to introduce various aspects of the art, which may be associated with embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art. [0004] Modern society is greatly dependent on the use of hydrocarbons for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface rock formations known as “reservoirs.” Removing hydrocarbons from reservoirs depends on numerous physical properties of the rock formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the rock formations, and the proportion of hydrocarbons present, among others. [0005] Various techniques have been developed to assist with flow control issues associated with construction, completion, and production of such wells. One technique that helps with flow control issues is known as “stimulation.” Stimulation is a process by which the flow of hydrocarbons between a formation and a wellbore is improved. This can be performed by any number of techniques, such as fracturing a rock surrounding the wellbore with a high-pressure fluid, injecting acid into a reservoir, or injecting steam into the reservoir to lower the viscosity of the hydrocarbons. One technique involves injecting fluids through the wellbore into the surrounding formation. This helps to increase the flow from production wells, for example, by increasing pressure within the formation. [0006] Moreover, water injection is also used to provide pressure support. For example, in order to produce oil from a reservoir, a pressure drop may first be applied on a well. That is, the pressure on the well should be lower than the pressure of the reservoir, so that oil can go from the reservoir to the well. However, when oil is produced from a reservoir, the reservoir pressure goes down with depletion. When this happens, the well pressure should be reduced further to keep producing oil. If the pressure gets too low, then the well may stop producing oil. To solve this problem, other wells nearby are used as injectors to pump water into the same reservoir and therefore get the reservoir pressure back up. In this manner, the reservoir may continue to produce oil via the well. [0007] In addition, such wells may also be used for carbon capture sequestration. Carbon capture sequestration is used to store carbon dioxide underground and thus reduce the total amount of carbon dioxide present in the environment above ground. Carbon capture sequestration involves the injection of carbon dioxide into available storage volumes in an underground reservoir. SUMMARY [0008] An embodiment described herein provides a well completion assembly including a liner extending into a reservoir. The liner includes a number of plugged injection check valves arranged along the liner into a number of sets corresponding to a number of zones of the reservoir. The liner is configured to inject fluid into the number of zones of the reservoir. [0009] Another embodiment described herein provides a method for injecting fluid into a reservoir. The method includes inserting a liner with sets of plugged injection check valves corresponding to different zones of the reservoir. The method includes injecting a fluid into a first zone of the reservoir via an unplugged set of injection check valves. The method also includes unplugging a first set of plugged injection check valves corresponding to an additional zone of the well. The method further includes injecting the fluid into the additional zone via the unplugged injection check valves. DESCRIPTION OF THE DRAWINGS [0010] The foregoing and other advantages of the present techniques may become apparent upon reviewing the following detailed description and drawings of non-limiting examples in which: [0011] FIG.1A is a cross-sectional view of a well that includes a liner with plugged injection check valves; [0012] FIG.1B is a cross-sectional view of a well that includes a liner with a set of unplugged injection check valves and a set of isolated injection check valves; [0013] FIG.1C is a cross-sectional view of a well that includes a liner with a third set of unplugged injection check valves and two sets of isolated injection check valves; [0014] FIG.2A is a cross-sectional view of a well that includes a cased and perforated liner with plugged injection check valves; [0015] FIG.2B is a cross-sectional view of a well that includes a cased and perforated liner with a set of unplugged injection check valves and a set of isolated injection check valves; [0016] FIG.2C is a cross-sectional view of a well that includes a cased and perforated liner with a third set of unplugged injection check valves and two sets of isolated injection check valves; [0017] FIG.3A is a cross-sectional view of a well that includes a liner with unplugged injection check valves at different segments of a completion; [0018] FIG.3B is a cross-sectional view of a well that includes a liner with three sets of unplugged injection check valves; [0019] FIG.3C is a cross-sectional view of a well that includes a liner with a fourth set of unplugged injection check valves; [0020] FIG.4A is a cross-sectional view of a well that includes a cased and perforated liner with unplugged injection check valves at different segments of a completion; [0021] FIG.4B is a cross-sectional view of a well that includes a cased and perforated liner with three sets of unplugged injection check valves; [0022] FIG.4C is a cross-sectional view of a well that includes a cased and perforated liner with a fourth set of unplugged injection check valves; [0023] FIG.5 is a process flow diagram of a method for injecting fluid into a well using sequentially removed plugs; and [0024] FIG.6 is a process flow diagram of a method for injecting fluid into a well using a progressive removal of different numbers of removable plugs in different segments of a completion. [0025] It should be noted that the figures are merely examples of the present techniques, and no limitations on the scope of the present techniques are intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the techniques. DETAILED DESCRIPTION [0026] In the following detailed description section, the specific examples of the present techniques are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for example purposes only and simply provides a description of the embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims. [0027] At the outset, and for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims. [0028] As used herein, the terms “a” and “an” mean one or more when applied to any embodiment described herein. The use of “a” and “an” does not limit the meaning to a single feature unless such a limit is specifically stated. [0029] As used herein, an “activator” or an “activation fluid” refers to the chemical that initiates and accelerates the dissolution or degradation of a material. [0030] As used herein, “bullheading” refers to pumping fluids into formation during well completion. [0031] The term “casing” refers to a protective lining for a wellbore. Any type of protective lining may be used, including those known to persons skilled in the art as liner, casing, tubing, etc. Casing may be segmented or continuous, jointed or unjointed, made of any material (such as steel, aluminum, polymers, composite materials, etc.), and may be expanded or unexpanded. [0032] As used herein, “degradable” refers to a mechanism of breaking down solid material in which the chemical structure of the material is modified. [0033] As used herein, “dissolution” and “dissolving” refers to a mechanism of breaking down solid material. During dissolution, the chemical structure of the material is preserved. [0034] As used herein, the terms “example,” exemplary,” and “embodiment,” when used with reference to one or more components, features, structures, or methods according to the present techniques, are intended to convey that the described component, feature, structure, or method is an illustrative, non-exclusive example of components, features, structures, or methods according to the present techniques. Thus, the described component, feature, structure or method is not intended to be limiting, required, or exclusive/exhaustive; and other components, features, structures, or methods, including structurally and/or functionally similar and/or equivalent components, features, structures, or methods, are also within the scope of the present techniques. [0035] As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, and combinations of liquids and solids. [0036] “Formation” refers to a subsurface region including an aggregation of subsurface sedimentary, metamorphic and/or igneous matter, whether consolidated or unconsolidated, and other subsurface matter, whether in a solid, semi-solid, liquid and/or gaseous state, related to the geological development of the subsurface region. A formation can be a body of geologic strata of predominantly one type of rock or a combination of types of rock, or a fraction of strata having substantially common sets of characteristics. A formation can contain one or more hydrocarbon-bearing subterranean formations. Note that the terms “formation,” “reservoir,” and “interval” may be used interchangeably, but may generally be used to denote progressively smaller subsurface regions, zones, or volumes. More specifically, a “formation” may generally be the largest subsurface region, while a “reservoir” may generally be a hydrocarbon-bearing or water-bearing zone within the geologic formation. Moreover, an “interval” may generally be a sub-region or portion of a reservoir. In some cases, a hydrocarbon-bearing zone, or reservoir, may be separated from other hydrocarbon-bearing zones by zones of lower permeability, such as mudstones, shales, or shale-like (i.e., highly-compacted) sands. [0037] A “hydrocarbon” is an organic compound that primarily includes the elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. As used herein, the term “hydrocarbon” generally refers to components found in oil and natural gas, such as CH₄, C₂H₂, C₂H₄, C₂H₆, C₃ isomers, C₄ isomers, benzene, and the like. [0038] As used herein, “injection check valves" are valves that allow flow in one direction downhole and prevent backflow. [0039] As used herein, a “joint” refers to a single unitary length of pipe. [0040] The term “liner” refers to a casing string that does not extend back to the wellhead or surface but is, instead, anchored or suspended from inside the bottom of the previous casing string using a liner hanger, for example. [0041] As used herein, the term “packer” refers to a type of sealing mechanism used to block the flow of fluids through a well or an annulus within a well. Packers can include, for example, open-hole packers, such as swelling elastomers, mechanical packers, or external casing packers, which can provide zonal segregation and isolation. [0042] The term “substantially,” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may depend, in some cases, on the specific context. [0043] The terms "well" and “wellbore” refer to holes drilled vertically, at least in part, and may also refer to holes drilled with deviated, highly-deviated, and/or horizontal sections. The term also includes wellhead equipment, surface casing, intermediate casing, and the like, typically associated with oil and gas wells. [0044] As used herein, a “well completion” is a group of equipment and operations that may be installed and performed to produce hydrocarbons from a subsurface reservoir. A well completion assembly may include the casing, production liner, completion fluid, gas lift valves, and other equipment used to prepare the well to produce hydrocarbons or inject fluids into the subsurface reservoir. Overview [0045] Fluids are injected into wells for various reasons. As one example, stimulation of a well is done by injecting stimulation fluids into a formation. For example, the stimulation can be done using bullheading, or by injecting the fluids using coiled tubing. Similarly, in another example, carbon capture sequestration (CCS) includes injecting liquid carbon dioxide into various intervals or zones of a reservoir. As yet another example, water injection is used for pressure support in wells, or for disposal of produced water. In all cases, injection conformance is an important functionality in a given completion design. For example, injection conformance is important in CCS applications in order to control zonal plume extension and maximize storage efficiency. However, injectors used in sandstone reservoirs are typically subject to impairment risks due to sand ingress caused by cross-flow and pressure shock waves occurring due to valve closures associated with well shut-in. [0046] The present techniques improve performance of injection check valves by providing systems and methods for the use of removable injection check valve plugs. In order to address the technical problems discussed above, the embodiments described herein combine the use of injection check valves together with removable plugging materials to selectively unplug new injection zones upwards from the bottom of a liner in a well. In various examples, the bottom may be lower relative to the zone to be simulated and thus not necessarily located at the very bottom of the liner. In addition, sets of injection check valves corresponding to zones where initial injection is not desired are temporarily isolated with plugged injection check valves. The plugged injection check valves are then unplugged at desired times, while still maintaining check valve functionality. In various embodiments, the plugged injection check valves are unplugged chemically by dissolving the material that prevents flow using an activation fluid or mechanically by introducing high pressures to overcome the strength of the removable injection check valve plugs. The techniques described herein thus provide a completion design that prevents cross-flow and considerably reduces sand ingress throughout the life of the well. [0047] FIG.1A is a cross-sectional view of a well 100 that includes tubing 101 coupled to a liner 102 with plugged injection check valves 104A, 104B, and 104C. The liner 102 also includes unplugged injection check valves 132A, discussed in greater detail below. The example of FIG.1A shows four injection check valves for each of plugged injection check valves 104A, 104B, and 104C. The well 100 defines a bore that extends from a surface 106 into a formation within the Earth’s subsurface. The formation may include several subsurface zones 108A, 108B, 108C, and 108D. For example, such zones may include hydrocarbon-bearing zones or carbon dioxide storage zones that are referred to collectively as a reservoir. In some embodiments, the reservoir includes mostly carbonate rock layers. In various embodiments, the reservoirs may also include any other types of rock layers, such as cemented sand layers. [0048] In various embodiments, the well 100 also includes a wellhead (not shown). The wellhead couples the tubing 101 of the well 100 to other equipment (not shown), such as a pump and a tank holding liquid carbon dioxide to be stored, or storing other fluids to be used for a stimulation process. For example, other fluids may include acid for a stimulation, a scale inhibition treatment, surfactants, or water for pressure support or disposal. [0049] The well 100 is completed by setting a series of tubulars into the formation. The well 100 may generally be described as having an upper completion including a tubing 101 and lower completion including liner 102. The tubulars in the upper completion of the well 100 include several strings of casing, such as a surface casing string 112, an intermediate casing string 114, and an inner casing string 116. In some embodiments, additional intermediate casing strings (not shown) are also included to provide support for the walls of the well 100. According to the embodiment shown in FIG. 1A, the surface casing string 112, the intermediate casing string 114, and the inner casing string 116, are hung from the surface 106, while a lower outer casing string 120 is hung from the bottom of the intermediate casing string 114 using a hanger 122. [0050] In various embodiments, the surface casing string 112 and the intermediate casing string 114 are set in place using cement 124. The cement 124 isolates unused upper intervals of the formation from the well 100 and each other. In the embodiment shown in FIG.1A-1C, the well 100 is set as an open-hole completion, meaning that the lower portion of the bore of well 100 is not supported by any casing or liner set in place using cement. Alternatively, in some embodiments, the well is a cased-hole completion, as shown and described in FIGS.2A-2C. [0051] The liner 102 of the well 100 includes a packer 126 that prevents injected fluid from traveling back up through an annulus 128 between the inner casing string 116 and the liner 102 in the well 100. [0052] The liner 102 in the lower completion of the well 100 includes a number of packers 130 that isolate different injection zones of the well 100. The packers 130 are placed along the outer diameter of the liner 102. The packers 130 may be any suitable type of packer, such as, for example, a swellable packer fabricated from a swelling elastomeric material. In various embodiments, each of the packers 130 isolate a set of injection check valves associated with each zone from the injection check valves of other zones. Thus, as shown in FIG.1A, injection fluid flowing through the unplugged injection check valves 132A is blocked from flowing towards the subsurface zone 108B by a packer 130 located between the unplugged injection check valves 132A and the plugged injection check valves 104A. [0053] According to various embodiments described herein, the liner 102 includes different zones separated by the packers 130. The zones correspond to different zones 108A-108D and enable controlled injection of fluid into the various zones 108A-108D. For example, the zones 108A-108D may be layers of different rock quality. The liner 102 includes a first set of unplugged injection check valves 132A located at the bottom of the liner 102. In various embodiments, the unplugged injection check valves 132A at the bottom of the liner 102 are unplugged when placed into the well 100. Thus, after packers 130 are deployed, a fluid may be pumped through the first set of unplugged injection check valves into the first zone 108A. In various embodiments, the fluid may be pumped through the first set of unplugged injection check valves into the first zone 108A based on an estimated volume capacity of the first zone 108A. In some embodiments, the fluid may be pumped into the first zone 108A for a predetermined amount of time. For example, the first zone 108A may be isolated for a reason that is non-volume related, such as packer failure, plugging, commercial term changes, etc. In one embodiment, a certain volume of fluid may be pumped into the first zone 108A. The total injected volume may depend on the estimated storage capacity of the associated zone 108A in the reservoir. [0054] In various embodiments, the plugged injection check valves 104A, 104B, and 104C may be plugged using any suitable type of plug to temporarily prevent fluid from flowing. In some embodiments, the plugged injection check valves 104A, 104B, and 104C are plugged using plugs made of a removable material. In various embodiments, the removable material is a degradable material or a dissolvable material. Dissolvable materials may include, for example, certain metals, such as iron, copper, aluminum readily dissolve in a concentrated acid. Dissolvable materials may also be made from stone, such as calcium carbonate, which also dissolves in acid. In addition, the temporary plugs may be alternatively made from a polylactic acid polymer material, which may also readily dissolve in acid. In various examples, the plugs can be included in each of the injection check valves during a manufacturing process to temporarily plug the injection check valves. In various embodiments, the plug material may include, but is not limited to, multilayered or monolithic composite alloys or polymers with high mechanical strength and high glass transition temperature. Alternatively, in some embodiments, the material can be removed by exposing the material to a solvent or an activator. In various embodiments, the material used for the plugs is insoluble in brine and drilling mud both at surface and downhole conditions. In various embodiments, the plugs are able to preserve integrity and mechanical properties for the duration of a treatment or injection and can withstand the differential pressure present during the injection of the stimulation fluids or carbon. In some embodiments, the plugs are mechanically removable using pressure or other mechanical methods. For example, the plugs can be removed using hydraulic or mechanical devices such as rupture discs. [0055] In various embodiments, the plugged injection check valves 104A, 104B, and 104C are plugged with different types of plugs in order to enable a multiple stage stimulation or carbon sequestration. As one example, a multi-stage carbon sequestration includes injection of carbon dioxide into a first zone via unplugged injection check valves 132A into a first zone 108A. After a predetermined volume or time, the unplugged injection check valves 132A are isolated using an isolation mechanism and a second zone is used to inject carbon into zone 108B by removing plugs from the plugged injection check valves 104A, as shown below in FIG.1B. In various embodiments, the times at which the plugged injection check valves 104A, 104B, and 104C are unplugged are specifically tailored based on the details of the specific implementation, as described further herein. As one example, in carbon sequestration embodiments, the times at which the plugging material is removed from the injection check valves in zones 108B-108D are based on the estimated volume capacity of each of the zones. For example, in some embodiments, the times are based on treatment volumes of carbon dioxide for each of the zones 108A-108D. [0056] Thus, in various embodiments, the bottom zone with unplugged injection check valves 132A is initially open to injection fluids utilizing conventional unplugged injection check valves. Injection into other zones is prevented by using plugged injection check valves 104A- 104C that are temporarily plugged by a removable material. Injection into these zones is enabled on a zone-by-zone basis by removing the material that prevents flow, while still maintaining check valve functionality, as described for two subsequent zones in FIGS.1B and 1C. [0057] FIG.1B is a cross-sectional view of a well that includes a liner 102 with a set of unplugged injection check valves 132B and a set of isolated injection check valves. FIG.1B includes similarly referenced elements from FIG.1A. The set of plugged injection check valves 104A of FIG.1A have been unplugged and thus now referred to as a set of unplugged injection check valves 132B. For example, the plugs of unplugged injection check valves 132B may have been removed using either dissolution or dissolving of the plug material. In addition, the first set of unplugged injection check valves of FIG.1A has been isolated using an isolation device 134A and are now referred to as a set of isolated injection check valves 132A. For example, the isolation device may be a bridge plug within the liner 102 that has been set above the unplugged set of injection check valves 132A of FIG.1A. In various embodiments, the bridge plug is a permanent, millable, or retrievable plug. Alternatively, in some embodiments, the isolation device is a ball or a dart that is dropped down the well. For example, the ball or dart stops once meeting a certain profile or ID, such that everything below the ball or dart is isolated. In various embodiments, the injection check valves 132A are isolated along with associated zone 108A using the isolation device 134A before unplugging the plugged injection check valves in a new zone such that injection only continues across the newly unplugged zone of the reservoir. In various embodiments, this zone-based injection enables control of zonal plume extension in order to maximize storage efficiency in the reservoir. In addition, the use of injection check valves generally along the completion increases the reliability of the completion by reducing sand ingress caused by cross-flow and pressure shock waves resulting from valve closures during well shut-in. [0058] In the embodiment of FIG.1B, injection of a fluid continues through unplugged injection check valves 132B into zone 108B. In various embodiments, the flow rate and time that the fluid is injected into unplugged injection check valves 132B is based on the particular characteristics of the zone 108B. For example, such characteristics may include permeability, total available storage volume, reservoir pressure, allowable pumping pressure, etc. [0059] FIG.1C is a is a cross-sectional view of a well that includes a liner 102 with a third set of unplugged injection check valves. FIG.1C includes similarly referenced elements from FIGS.1A and 1B. In addition, the unplugged set of injection check valves 132B has been isolated via isolation device 134B and now referred to as a second set of isolated injection check valves 132B. For example, the isolation device 134B may be a bridge plug that is installed in the liner 102 just above the injection check valves 132B. In various embodiments, the isolated injection check valves 132B are isolated using the isolation device 134B located between the second zone containing the isolated injection check valves 132B and a sequentially higher third zone containing newly unplugged injection check valves 132C. In particular, previously plugged injection check valves 104B have been unplugged and are now referred to as unplugged injection check valves 132C. [0060] In various embodiments, the liner 102 thus includes an additional number of isolation devices 134A and 134B to sequentially shut off each of the number of zones 108C and 108D sequentially from bottom to top after a fluid is injected separately into each of the zones. In this manner, the isolated zones enable injection for each of the zones 108A-108D to be based on the characteristics of each of their associated zones in the reservoir. In various embodiments, the rate of injection and time of injection can be based on the permeability, or size, of each of the associated zones 108A-108D in the reservoir, among other factors. In this regard, the isolation of zones 108A-108D during and after injection also prevents the differing characteristics of other zones, such as excess permeability in one zone of the reservoir, from affecting the optimal storage or stimulation of another zone. In the example of FIG.1C, a focused injection of fluid into zone 108C is thus performed via unplugged injection check valves 132C. In various embodiments, the higher zone 108D may similarly be injected. [0061] Although the example of FIG.1 shows four injection check valves for each of plugged injection check valves 104A, 104B, 104C, in various embodiments, different numbers of check valves are used in each zone to improve conformance. Moreover, in various embodiment, the various different numbers of valves may be run with or without plugs in different segments of the completion, and a different number of check valves used in each zone to improve conformance, as shown and described in the examples of FIGS.3A-3C. [0062] In one embodiment, a carbon sequestration is performed by maximizing the volume of carbon dioxide injected into each of the zones 108A-108D in the reservoir without exceeding the boundaries of zones 108A-108D. For example, a volume of carbon dioxide is injected into each of the zones 108A-108D at a rate and for a time based on the characteristics of each particular zone. The boundaries of each zone may thus be maximized, resulting in an improvement in total stored carbon dioxide in the reservoir. [0063] In another embodiment, a reservoir management process includes using a water injector well. For example, the water injector well is used in a subsea development that contains oil offshore. The process includes injecting water into the wells to provide pressure to the reservoir at various zones to assist in extracting the oil from each of the zones. In another embodiment, the water injector could also be used as a wastewater disposal well. In this embodiment, the reservoir that is being used to inject the water does not necessarily contain hydrocarbons. Thus, in various examples, the water is injected into each of the zones 108A- 108D at a rate and for a time based on the characteristics of each particular zone. [0064] FIG.2A is a cross-sectional view of a well 200 that includes a cased and perforated liner 202 with plugged injection check valves. FIG. 2A includes similarly referenced elements described with respect to FIG.1A. In addition, the well 200 includes cased and perforated liner 202. For example, the cased and perforated liner 202 may include a casing that is made of carbon steel or a corrosion-resistant alloy (CRA). The cased and perforated liner 202 is also perforated in order to enable flow between the wellbore and the reservoir. [0065] FIG.2B is a cross-sectional view of a well 200 that includes a cased and perforated liner 202 with a set of unplugged injection check valves and a set of isolated injection check valves. FIG.2B includes similarly referenced elements described with respect to FIG. 1B. Thus, zone 108A and associated injection check valves 132A are similarly isolated using isolation device 134A before injection check valves 132B are unplugged. A determined volume of fluid is then similarly pumped via the check valves 132B into zone 108B. [0066] FIG.2C is a cross-sectional view of a well 200 that includes a cased and perforated liner 202 with a third set of unplugged injection check valves and two sets of isolated injection check valves. FIG. 2C includes similarly referenced elements described with respect to FIG. 1C. In particular, zone 108B and associated injection check valves 132B are similarly isolated using isolation device 134B before injection check valves 132C are unplugged. A determined volume of fluid is then similarly pumped via the unplugged injection check valves 132C into zone 108C. [0067] FIG.3A is a cross-sectional view of a well 300 that includes a liner 102 with unplugged injection check valves 132D and 132E and plugged injection check valves 104D and 104E at different segments of a completion. In particular, the unplugged injection check valves 132D and 132E of well 300 are located at the bottom and third from the bottom. In various embodiments, the unplugged injection check valves 132D and 132E include different numbers of injection check valves. For example, although four injection check valves are shown in FIG. 3A, in various embodiments, unplugged injection check valves 132D can include more or less valves, while the injection check valves 132E include a different number of valves. In various embodiments, a fluid is then pumped through unplugged injection check valves 132D and 132E. For example, a predetermined volume of the fluid may be pumped for a determined amount of time. [0068] FIG.3B is a cross-sectional view of a well 300 that includes a liner with three sets of unplugged injection check valves 132D, 132E, and 132F. FIG. 3B includes similarly referenced elements of FIG.3A. In FIG.3B, an additional set of plugged injection check valves 132F are unplugged by removing the plugs to enable fluid to flow through an additional set of unplugged injection check valves 132F. In various embodiments, a fluid is then pumped through unplugged injection check valves 132D, 132D, and 132F. The fluid does not pump through plugged injection check valves 104D. [0069] FIG.3C is a cross-sectional view of a well 300 that includes a liner with a fourth set of unplugged injection check valves 132G. In FIG. 3C, an additional set of plugged injection check valves 132G are unplugged by removing the plugs to enable fluid to flow through an additional set of unplugged injection check valves 132G, in addition to unplug injection check valves 132D, 132E, and 132F. [0070] FIG.4A is a cross-sectional view of a well 400 that includes a cased and perforated liner with unplugged injection check valves 132D and 132E and plugged injection check valves 104D and 104E at different segments of a completion. FIG.4A includes similarly referenced elements described in FIG.3A. In the example of FIG.4A, the tubing string with the plugged injection check valves 104E, 104D, unplugged injection check valves 132D, 132E and packers 130 is run inside a cased and perforated liner 202 that is cemented. As described in FIG.3A, more than one zone has unplugged check valves, and eventually the plugging material is removed from the other zones without isolating the initial injection zones, as shown in FIGS.4B and 4C. In FIG.4A, a fluid is initially pumped through unplugged injection check valves 132D and 132E. For example, a predetermined volume of the fluid may be pumped for a determined amount of time. [0071] FIG.4B is a cross-sectional view of a well 400 that includes a cased and perforated liner 202 with three sets of unplugged injection check valves 132D, 132E, and 132F. FIG.4B includes similarly referenced elements described in FIG.3B. As shown in FIG.4B, an additional set of plugged injection check valves 132F are unplugged by removing the plugs to enable fluid to flow through an additional set of unplugged injection check valves 132F. In various embodiments, a fluid is then pumped through unplugged injection check valves 132D, 132E, and 132F. [0072] FIG.4C is a cross-sectional view of a well 400 that includes a cased and perforated liner 202 with a fourth set of unplugged injection check valves 132G. FIG. 4C includes similarly referenced elements described in FIG.3C. For example, as shown in FIG.4C, an additional set of plugged injection check valves 132G are unplugged by removing the plugs to enable fluid to flow through an additional set of unplugged injection check valves 132G, in addition to unplug injection check valves 132D, 132E, and 132F.FIG.5 is a process flow diagram of a method 500 for injecting fluid into a well using sequentially removed plugs. The method 500 is implemented by a tubing that extends along a portion of a well that is proximate to a reservoir. In some embodiments, the reservoir includes a number of zones to be used for carbon sequestration. In some embodiments, the reservoir includes a number of hydrocarbon- bearing or potentially carbon-storing or water-storing zones. [0073] The method 500 begins at block 502, at which a liner with a number of plugged injection check valves corresponding to different zones of a reservoir is inserted into a well. In various embodiments, the liner includes a number of sets of plugged injection check valves that correspond to higher zones of the reservoir. In various embodiments, the liner includes a number of packers to isolate the different zones of the well. In one embodiment, the packers are swellable packers that expand after the liner is lowered into the well. In various embodiments, at least one of the sets of injection check valves are unplugged. In one embodiment, a lowest set of injection check valves in the liner is an unplugged set of any suitable injection check valves without any plugging material. [0074] At block 504, a fluid is injected into a first zone of the reservoir via an unplugged set of bottom injection check valves. In some embodiments, the fluid includes carbon dioxide for carbon sequestration. In some embodiments, the fluid is a stimulation fluid used to stimulate various zones in a reservoir. In some embodiments, the fluid is water. For example, the water may be injected for pressure support or for wastewater disposal. In various embodiments, a specified fluid volume is injected into the first zone In one embodiment, the total volume of injected fluid into the first zone is based on the storage capacity of the zone. In some embodiments, the fluid is injected into the first zone for a predetermined amount of time. [0075] At block 506, the first zone is shut off via an isolation device. In one embodiment, the isolation device is a bridge plug above the first zone of the liner that prevents further injection flow into the first zone. In some embodiments, the isolation device is a ball or dart that is lowered into the well to isolate the first zone. [0076] At block 508, a first set of plugged injection check valves corresponding to a sequentially higher zone of the reservoir are unplugged. For example, the sequentially higher zone of the reservoir may have different characteristics than the first zone of the reservoir. In various embodiments, the plugged injection check valves are unplugged chemically. For example, the plugged injection check valves are unplugged using an activation fluid to dissolve or degrade the plugging material in the plugged injection check valves. In some embodiments, the activation fluid is an acid. For example, the acid is hydrochloric acid. In one embodiment, a 15% hydrochloric acid solution is used. In some embodiments, the activation fluid is an oil. In some embodiments, the plugged injection check valves are unplugged mechanically. For example, the plugged injection check valves may be unplugged by raising the pressure at the plugs beyond a specific threshold pressure. In some embodiments, the plugged injection check valves are unplugged by increasing the temperature at the injection check valves to exceed a threshold temperature. [0077] At block 510, the fluid is injected into the sequentially higher zone via the unplugged injection check valves. In various embodiments, a volume of fluid is injected into the sequentially higher zone based on the characteristics of the sequentially higher zone, such as permeability and capacity of the sequentially higher zone. [0078] At decision diamond 512, a determination is made as to whether additional zones are to be injected. If additional zones are to be injected, then the method 500 proceeds at block 506. If no additional zones are to be injected, then the method proceeds to block 514. In various embodiments, the number of zones is based on the characteristics of the reservoir into which carbon dioxide is stored, or other fluids are injected. Thus, the method may include shutting off the sequentially higher zone via a second isolation device, unplugging a second set of plugged injection check valves associated with a second sequentially higher zone, and injecting the fluid into the second sequentially higher zone. The second isolation device is located under the second set of plugged injection check valves. [0079] At block 514, the method 500 ends. In various embodiments, the liner and packers are left in the well. [0080] The process flow diagram of FIG.5 is not intended to indicate that the steps of the method 500 are to be executed in any particular order, or that all of the steps of the method 500 are to be included in every case. Further, any number of additional steps not shown in FIG.5 may be included within the method 500, depending on the details of the specific implementation. [0081] FIG.6 is a process flow diagram of a method 600 for injecting fluid into a well using a progressive removal of different numbers of removable plugs in different segments of a completion. The method 600 is implemented by a tubing that extends along a portion of a well that is proximate to a reservoir. In some embodiments, the reservoir includes a number of zones to be used for carbon sequestration. In some embodiments, the reservoir includes a number of hydrocarbon-bearing or potentially carbon-storing zones. In some embodiments, the reservoir includes a number of potentially water-storing zones. [0082] The method 600 begins at block 602, at which a liner with a number of plugged injection check valves corresponding to different zones of a reservoir is inserted into a well. In various embodiments, the liner includes a number of sets of plugged injection check valves that correspond to different zones of the reservoir. In various embodiments, the liner includes a number of packers to isolate the different zones of the well. In one embodiment, the packers are swellable packers that expand after the liner is lowered into the well. In various embodiments, at least one of the sets of injection check valves are unplugged. In one embodiment, two non- adjacent sets of injection check valves are unplugged. In some embodiments, some of the injection check valve sets may have may have less injection check valves than the other sets. For example, one zone may have less injection check valves than the other zones to create some pressure resistance and help divert the fluid into the other zone. [0083] At block 604, a fluid is injected into a first set of zones of the reservoir via multiple sets of unplugged injection check valves. In some embodiments, the fluid includes carbon dioxide for carbon sequestration. In some embodiments, the fluid is a stimulation fluid used to stimulate various zones of a reservoir. In some embodiments, the fluid is water. For example, the water may be injected for pressure support or for waste water disposal. In various embodiments, the fluid is injected into the first set of zones for a determined volume of fluid. In one embodiment, the fluid is injected into the first set of zones for a determined amount of time. [0084] At block 606, a first set of plugged injection check valves corresponding to an additional zone of the reservoir are unplugged. For example, the additional zone of the reservoir may have different characteristics than the first zone of the reservoir. In various embodiments, the plugged injection check valves are unplugged chemically. For example, the plugged injection check valves are unplugged using an activation fluid to dissolve or degrade the plugging material in the plugged injection check valves. In some embodiments, the activation fluid is an acid. For example, the acid is hydrochloric acid. In one embodiment, a 15% hydrochloric acid solution is used. In some embodiments, the activation fluid is an oil. In some embodiments, the plugged injection check valves are unplugged mechanically. For example, the plugged injection check valves may be unplugged by raising a pressure at the plugs beyond a specific threshold pressure. In some embodiments, the plugged injection check valves are unplugged by increasing the temperature at the injection check valves to exceed a threshold temperature. [0085] At block 608, the fluid is injected into the unplugged sets of injection check valves. In various embodiments, the fluid is injected into the zones corresponding to the unplugged injection check valves for a predetermined volume of fluid or a predetermined amount of time. [0086] At decision diamond 610, a determination is made as to whether additional zones are to be injected. If additional zones are to be injected, then the method 600 proceeds at block 606. If no additional zones are to be injected, then the method proceeds to block 612. [0087] At block 612, the method 600 ends. In some embodiments, the liner and packers are left in the well. [0088] The process flow diagram of FIG.6 is not intended to indicate that the steps of the method 600 are to be executed in any particular order, or that all of the steps of the method 600 are to be included in every case. Further, any number of additional steps not shown in FIG.6 may be included within the method 600, depending on the details of the specific implementation. Additional Embodiments [0089] In one or more embodiments, the present techniques may be susceptible to various modifications and alternative forms, such as the following embodiments as noted in paragraphs 1 to 26: 1. A well completion assembly, including a liner extending into a reservoir, the liner including a number of plugged injection check valves arranged along the liner into a number of sets corresponding to a number of zones of the reservoir, where the liner is configured to inject fluid into the number of zones of the reservoir. 2. The well completion assembly recited in paragraph 1, where the liner includes a number of packers to isolate the zones. 3. The well completion assembly recited in any of paragraphs 1-2, where the liner is configured to inject fluid into a single zone of the number of zones at a time using isolation. 4. The well completion assembly recited in any of paragraphs 1-3, where the liner is configured to inject fluid into a single zone of the number of zones at a time sequentially using isolation. 5. The well completion assembly recited in any of paragraphs 1-4, where the liner is configured to inject fluid into a number of zones at a time without isolation. 6. The well completion assembly recited in any of paragraphs 1-5, where the liner includes a set of unplugged injection check valves corresponding to a lowest zone of the reservoir. 7. The well completion assembly recited in any of paragraphs 1-6, where the liner is configured to inject fluid into the number of zones of the reservoir sequentially from bottom up. 8. The well completion assembly recited in any of paragraphs 1-7, where the liner is configured to inject fluid into the number of zones in a predetermined order. 9. The well completion assembly recited in any of paragraphs 1-8, where the fluid includes water, carbon dioxide, and/or a stimulation fluid. 10. The well completion assembly recited in any of paragraphs 1-9, where a plugging material of the plugged injection check valves is removable using an activation fluid. 11. The well completion assembly recited in any of paragraphs 1-10, where a plugging material of the plugged injection check valves is mechanically removable. 12. The well completion assembly recited in any of paragraphs 1-11, where the plugged injection check valves are configured to be unplugged using different target pressures. 13. The well completion assembly recited in any of paragraphs 1-12, where the plugged injection check valves corresponding to each zone are configured to be unplugged at the same time. 14. The well completion assembly recited in any of paragraphs 1-13, where the plugged injection check valves corresponding to each zone are configured to be unplugged using different target temperatures. 15. The well completion assembly recited in any of paragraphs 1-14, including a number of isolation devices inside the liner to isolate each of the number of zones of the reservoir after the fluid is injected into each of the zones. 16. The well completion assembly recited in any of paragraphs 1-15, where the well completion includes a cased and perforated liner that is cemented. 17. The well completion assembly recited in any of paragraphs 1-16, where the subset of the number of zones where fluids are injected are separated by a set of plugged zones. 18. A method for injecting fluid into a reservoir, including inserting a liner with sets of plugged injection check valves corresponding to different zones of the reservoir; injecting a fluid into a first zone of the reservoir via a set of unplugged injection check valves; unplugging a first set of plugged injection check valves corresponding to an additional zone; and injecting the fluid into the unplugged first set of injection check valves. 19. The method recited in paragraph 18, including isolating the first zone via an isolation device before unplugging the first set of plugged injection check valves. 20. The method recited in any of paragraphs 18-19, where injecting the fluid into the first zone includes injecting a determined volume of the fluid for a determined amount of time. 21. The method recited in any of paragraphs 18-20, wherein injecting the fluid into the additional zones includes injecting a determined volume of fluid for a determined amount of time. 22. The method recited in any of paragraphs 18-21, where unplugging the first set of plugged injection check valves includes using an activation fluid. 23. The method recited in any of paragraphs 18-22, where unplugging the first set of plugged injection check valves includes increasing a pressure at the plugged injection check valves to a pressure that exceeds a threshold pressure. 24. The method recited in any of paragraphs 18-23, including shutting off a sequentially higher zone via a second isolation device, unplugging a second set of plugged injection check valves at a second sequentially higher zone, and injecting the fluid into the second sequentially higher zone. 25. The method recited in paragraph 24, where the second isolation device is located under the second sequentially higher zone of a well. 26. The method recited in any of paragraphs 24-25 where unplugging the second set of plugged injection check valves includes using a different activation fluid than an activation fluid used to unplug the first set of plugged injection check valves. 27. The method recited in any of paragraphs 18-26, including, in response to detecting an additional zone to inject, unplugging a second set of plugged injection check valves corresponding to another additional zone of a well; and injecting the fluid into the unplugged injection check valves. [0090] While the embodiments described herein are well-calculated to achieve the advantages set forth, it will be appreciated that the embodiments described herein are susceptible to modification, variation, and change without departing from the spirit thereof. Indeed, the present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Claims

CLAIMS What is claimed is: 1. A well completion assembly, comprising a liner extending into a reservoir, the liner comprising: a plurality of plugged injection check valves arranged along the liner into a plurality of sets corresponding to a plurality of zones of the reservoir, wherein the liner is configured to inject fluid into the plurality of zones of the reservoir.

2. The well completion assembly of claim 1, wherein the liner comprises a plurality of packers to isolate the zones.

3. The well completion assembly of claim 1, wherein the liner is configured to inject fluid into a single zone of the plurality of zones at a time using isolation.

4. The well completion assembly of claim 1, wherein the liner is configured to inject fluid into a single zone of the plurality of zones at a time sequentially using isolation.

5. The well completion assembly of claim 1, wherein the liner is configured to inject fluid into a plurality of zones at a time without isolation.

6. The well completion assembly of claim 1, wherein the liner comprises a set of unplugged injection check valves corresponding to a lowest zone of the reservoir.

7. The well completion assembly of claim 1, wherein the liner is configured to inject fluid into the plurality of zones of the reservoir sequentially from bottom up.

8. The well completion assembly of claim 1, wherein the liner is configured to inject fluid into the plurality of zones in a predetermined order.

9. The well completion assembly of claim 1, wherein the fluid comprises water, carbon dioxide, and/or a stimulation fluid.

10. The well completion assembly of claim 1, wherein a plugging material of the plugged injection check valves is removable using an activation fluid.

11. The well completion assembly of claim 1, wherein a plugging material of the plugged injection check valves is mechanically removable.

12. The well completion assembly of claim 1, wherein the plugged injection check valves are configured to be unplugged using different target pressures.

13. The well completion assembly of claim 1, wherein the plugged injection check valves corresponding to each zone are configured to be unplugged at the same time.

14. The well completion assembly of claim 1, wherein the plugged injection check valves corresponding to each zone are configured to be unplugged using different target temperatures.

15. The well completion assembly of claim 1, comprising a plurality of isolation devices inside the liner to isolate each of the plurality of zones of the reservoir after the fluid is injected into each of the zones.

16. The well completion assembly of claim 1, wherein the well completion comprises a cased and perforated liner that is cemented.

17. The well completion assembly of claim 1, wherein the subset of the plurality of zones where fluids are injected are separated by a set of plugged zones.

18. A method for injecting fluid into a reservoir, comprising: inserting a liner with sets of plugged injection check valves corresponding to different zones of the reservoir; injecting a fluid into a first zone of the reservoir via a set of unplugged injection check valves; unplugging a first set of plugged injection check valves corresponding to an additional zone; and injecting the fluid into the unplugged first set of injection check valves.

19. The method of claim 18, comprising isolating the first zone via an isolation device before unplugging the first set of plugged injection check valves.

20. The method of claim 18, wherein injecting the fluid into the first zone comprises injecting a determined volume of the fluid for a determined amount of time.

21. The method of claim 20, wherein injecting the fluid into the additional zones comprises injecting a determined volume of fluid for a determined amount of time.

22. The method of claim 18, wherein unplugging the first set of plugged injection check valves comprises using an activation fluid.

23. The method of claim 18, wherein unplugging the first set of plugged injection check valves comprises increasing a pressure at the plugged injection check valves to a pressure that exceeds a threshold pressure.

24. The method of claim 18, comprising shutting off a sequentially higher zone via a second isolation device, unplugging a second set of plugged injection check valves at a second sequentially higher zone, and injecting the fluid into the second sequentially higher zone.

25. The method of claim 24, wherein the second isolation device is located under the second sequentially higher zone of a well.

26. The method of claim 24, wherein unplugging the second set of plugged injection check valves comprises using a different activation fluid than an activation fluid used to unplug the first set of plugged injection check valves.

27. The method of claim 18, comprising: in response to detecting an additional zone to inject, unplugging a second set of plugged injection check valves corresponding to another additional zone of a well; and injecting the fluid into the unplugged injection check valves.