Systems and methods for increasing subsurface greenhouse gas storage capacity

Abstract

A method for storing a greenhouse gas in a subterranean permeable formation 40 positioned beneath a terranean surface 4 and containing a native liquid 42 includes (a) injecting a drainage fluid into t

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] Not applicable. STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002] Not applicable. BACKGROUND

[0003] Earthen subterranean formations have been used to store various foreign materials in a variety of different applications. In one such application subterranean formations are used to store greenhouse gasses (e.g., carbon in the form of carbon dioxide (CO2)) in a process sometimes referred to as greenhouse gas sequestration or carbon capture and storage (CCS). In some instances, greenhouse gas sequestration processes are implemented by artificial capture and sequestration of greenhouse gasses produced by varying industrial operations (e.g., through the burning of fossil fuels) in subterranean formations including reservoirs, aquifers, and other subterranean permeable formations. Particularly, in at least some applications a greenhouse gas is injected into a permeable formation via a wellbore which extends from the terranean surface and penetrates the permeable formation. The greenhouse gas injected into the permeable formation may remain captured therein for long-term storage so as to reduce greenhouse gas emissions. SUMMARY

[0004] An embodiment of a method for storing a greenhouse gas in a subterranean permeable formation positioned beneath a terranean surface and containing a native liquid comprises (a) injecting a drainage fluid into the permeable formation via at least one wellbore extending from the terranean surface and penetrating the permeable formation to increase a gas saturation of the permeable formation whereby at least a portion of the injected drainage fluid is trapped within pores of the permeable formation, and (b) injecting, following (a), the greenhouse gas into the permeable formation via the at least one wellbore to store at least a portion of the greenhouse gas within the permeable formation. In some embodiments, the permeable formation comprises a saline aquifer. In some embodiments, the drainage fluid comprises carbon dioxide. In certain embodiments, the greenhouse gas comprises carbon dioxide. In certain embodiments, the drainage fluid is injected into the permeable formation at a rate of 0.5-2 million tons per year. In some embodiments, the method comprises (c) injecting an imbibition liquid into the permeable formation via the at least one wellbore to trap at least some of the drainage fluid within pores of the permeable formation. In some embodiments, (a) comprises drainage fluid into the permeable formation at a predefined pressure which is greater than a pore pressure of the permeable formation but less than a fracture pressure of the permeable formation. In certain embodiments, the at least one wellbore comprises an injection well having an inlet at the terranean surface for injecting a fluid into the wellbore, and an outlet within the permeable formation for injecting the fluid into the permeable formation.

[0005] An embodiment of a method of storing a greenhouse gas in a subterranean permeable formation positioned beneath a terranean surface and containing a native liquid comprises (a) injecting a drainage fluid into the permeable formation via at least one injection wellbore extending from the terranean surface and penetrating the permeable formation to increase a gas saturation of the permeable formation, (b) injecting, following (a), the greenhouse gas into the permeable formation via the at least one injection wellbore to store at least a portion of the greenhouse gas within the permeable formation, and (c) discharging, in response to at least one of (a) and (b), the native liquid from the permeable formation and into at least one production wellbore extending from the permeable formation to the terranean surface. In certain embodiments, the permeable formation comprises a saline aquifer and the native liquid comprises brine. In some embodiments, the greenhouse gas comprises carbon dioxide. In some embodiments, the drainage fluid comprises carbon dioxide. In certain embodiments, the method comprises (d) injecting, following (a), an imbibition liquid into the permeable formation via the at least one wellbore to trap at least some of the drainage fluid within pores of the permeable formation. In certain embodiments, the imbibition liquid comprises water.

[0006] An embodiment of a method for storing a greenhouse gas in a subterranean permeable formation positioned beneath a terranean surface and containing a native liquid comprises (a) injecting a drainage fluid into the permeable formation via at least one wellbore extending from the terranean surface and penetrating the permeable formation to increase a gas saturation of the permeable formation, (b) injecting, following (a), an imbibition liquid into the permeable formation via the at least one wellbore to trap at least some of the drainage fluid within pores of the permeable formation, and (c) injecting, following (b), the greenhouse gas into the permeable formation via the at least one wellbore to store at least a portion of the greenhouse gas within the permeable formation. In some embodiments, the imbibition liquid comprises water. In some embodiments, the permeable formation comprises a saline aquifer. In certain embodiments, the greenhouse gas comprises carbon dioxide. In certain embodiments, the drainage fluid comprises carbon dioxide. In some embodiments, the method comprises (d) discharging, in response to at least one of (a), (b), and (c), the native liquid from the permeable formation and into at least one production wellbore extending from the permeable formation to the terranean surface.

[0007] Embodiments described herein comprise a combination of features and characteristics intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical characteristics of the disclosed embodiments in order that the detailed description that follows may be better understood. The various characteristics and features described above, as well as others, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes as the disclosed embodiments. It should also be realized that such equivalent constructions do not depart from the spirit and scope of the principles disclosed herein. BRIEF DESCRIPTION OF THE DRAWINGS

[0008] For a detailed description of disclosed exemplary embodiments, reference will now be made to the accompanying drawings in which:

[0009] Figure 1 is a schematic illustration of an embodiment of a greenhouse gas sequestration system in a first state in accordance with principles disclosed herein;

[0010] Figure 2 is a zoomed-in schematic illustration of a subterranean permeable formation in a first state in accordance with principles disclosed herein;

[0011] Figure 3 is a schematic illustration of the greenhouse gas sequestration system of Figure 1 in a second state in accordance with principles disclosed herein;

[0012] Figure 4 is a zoomed-in schematic illustration of the permeable formation of Figure 2 in a second state in accordance with principles disclosed herein;

[0013] Figure 5 is a schematic illustration of the greenhouse gas sequestration system of Figure 1 in a third state in accordance with principles disclosed herein;

[0014] Figure 6 is a zoomed-in schematic illustration of the permeable formation of Figure 2 in a third state in accordance with principles disclosed herein;

[0015] Figure 7 is a schematic illustration of the greenhouse gas sequestration system of Figure 1 in a fourth state in accordance with principles disclosed herein;

[0016] Figure 8 is a zoomed-in schematic illustration of the permeable formation of Figure 2 in a fourth state in accordance with principles disclosed herein;

[0017] Figure 9 is an exemplary graph illustrating remaining liquid saturation in a subterranean permeable formation as a function of initial liquid saturation in accordance with principles disclosed herein;

[0018] Figure 10 is a schematic illustration of another embodiment of a greenhouse gas sequestration system in accordance with principles disclosed herein;

[0019] Figure 11 is a schematic illustration of another embodiment of a greenhouse gas sequestration system in accordance with principles disclosed herein;

[0020] Figure 12 is a schematic illustration of another embodiment of a greenhouse gas sequestration system in accordance with principles disclosed herein;

[0021] Figure 13 is a schematic illustration of another embodiment of a greenhouse gas sequestration system in accordance with principles disclosed herein;

[0022] Figure 14 is a schematic illustration of another embodiment of a greenhouse gas sequestration system in accordance with principles disclosed herein;

[0023] Figure 15 is a schematic illustration of another embodiment of a greenhouse gas sequestration system in accordance with principles disclosed herein;

[0024] Figure 16 is a flowchart of an embodiment of a method for storing a greenhouse gas in a subterranean permeable formation containing a native liquid in accordance with principles disclosed herein;

[0025] Figure 17 is a flowchart of another embodiment of a method for storing a greenhouse gas in a subterranean permeable formation containing a native liquid in accordance with principles disclosed herein; and

[0026] Figure 18 is a flowchart of another embodiment of a method for storing a greenhouse gas in a subterranean permeable formation containing a native liquid in accordance with principles disclosed herein. DETAILED DESCRIPTION

[0027] The following discussion is directed to various embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

[0028] In the following discussion and in the claims, the terms "including" and "comprising" are used in an open-ended fashion, and thus should be interpreted to mean "including, but not limited to... Also, the term "couple" or "couples" is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection as accomplished via other devices, components, and connections. In addition, as used herein, the terms "axial" and "axially" generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms "radial" and "radially" generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Any reference to up or down in the description and the claims is made for purposes of clarity, with “up”, “upper”, “upwardly”, “uphole”, or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly”, “downhole”, or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation. Additionally, the term “about” is intended to cover deviations of + / - 5%.

[0029] As described above, carbon sequestration systems may assist in mitigating greenhouse gas emissions by artificially transporting greenhouse gasses (e.g., CO2) generated by industrial operations into a subterranean permeable formation (e.g., a saline aquifer) in which the injected greenhouse gas remains captured for long-term storage. In at least some applications, the greenhouse gas is delivered to the permeable formation via a wellbore (e.g., an injection well) extending from the terranean surface and which penetrates the permeable formation. In this manner, the greenhouse gas may be conveyed from a surface assembly located at an uphole end of the wellbore and transported (e.g., via the operation of one or more surface pumps and / or compressors of the surface assembly) through the wellbore whereby the greenhouse gas may be delivered to the permeable formation for storage therein.

[0030] Conventionally, greenhouse gasses, as part of a greenhouse gas sequestration process, are injected into a permeable formation such as an aquifer containing a native liquid (e.g., water or brine) where the aquifer is entirely (100%) saturated by the native liquid. As the greenhouse gas is injected into the aquifer, a portion of the native liquid is swept from the aquifer (e.g., into a neighboring subterranean formation or a production wellbore in fluid communication with the permeable formation), reducing the saturation of the permeable formation by the native liquid. However, a substantial amount of the native liquid may remain unswept by the greenhouse gas and thus may continue to reside in the permeable formation such that the formation remains partially saturated by the native liquid (e.g., 50% saturated by the native liquid). Thus, only a portion of the pore space of the permeable formation (e.g., 50% of the formation) may be occupied by the greenhouse gas while the remainder of the pore space is occupied by the unswept native liquid, substantially reducing the capacity of the permeable formation for storing the greenhouse gas and thus ultimately limiting the volume of greenhouse gas that may be stored in the permeable formation.

[0031] Accordingly, embodiments of systems and methods for storing a greenhouse gas in a subterranean permeable formation containing a native liquid are disclosed herein. In an embodiment, the saturation of the permeable formation by the native liquid is first artificially reduced prior to injecting the greenhouse gas into the permeable formation so as to minimize the final or residual saturation of the permeable formation by the native liquid (e.g., the saturation of the formation by the native liquid following injection of the greenhouse gas into the permeable formation) whereby the capacity of the permeable formation for storing the greenhouse gas is maximized. Particularly, it may be understood that a fundamental property of permeable formations is that a relationship exists between the initial saturation (e.g., the saturation of the permeable formation by the native liquid just prior to injection of the greenhouse gas) and the residual saturation of the permeable formation. Thus, if the permeable formation begins with a high initial saturation by the native liquid the residual saturation of the formation by the native liquid will generally be greater than in instances in which the formation begins with a relatively lower initial saturation by the native liquid.

[0032] In an embodiment, the drainage fluid injected into the permeable formation is trapped within pores of the permeable formation by influx of brine to reduce the initial saturation of the permeable formation to the native fluid prior to injection of the greenhouse gas into the permeable formation. The resulting 2-phase structure formed within the permeable formation may comprise CO2 in brine or trapped CO2. In this manner, the initial saturation of the permeable formation may be substantially reduced (e.g., from approximately 100% saturation by the native liquid to approximately 60% to 80% saturation by the native liquid) and the pore space of the permeable formation previously occupied by the native liquid is now occupied by the drainage fluid. The drainage fluid used to reduce the initial saturation of the permeable formation is miscible with the greenhouse gas. In some embodiments, the drainage fluid may also comprise a greenhouse gas (e.g., the drainage fluid and the greenhouse gas may each comprise CO2). In some embodiments, the drainage fluid injected into the permeable formation may be a gas, a liquid, a supercritical fluid, and combinations thereof.

[0033] As described above, the drainage fluid is injected into or provided to the permeable formation in a manner in which the drainage fluid is trapped within the pores of the subterranean formation, where the trapping of the drainage fluid in the pores of the formation reduces the initial saturation to the native liquid of the permeable formation. In some embodiments, an imbibition liquid is injected into the permeable formation following injection of the drainage fluid therein so as to trap the drainage fluid within the pores of the permeable formation prior to injection of the greenhouse gas into the permeable formation. The imbibition liquid is miscible with the native liquid of the permeable formation. For example, both the native liquid and the imbibition liquid comprise water (e.g., brine) in some embodiments. In other embodiments, the greenhouse gas may be injected into the permeable formation following the injection of the drainage fluid (e.g., without the injection of imbibition liquid) after a predefined period of time during which a plume of the drainage fluid is permitted to form and migrate (e.g., to a dome of the permeable formation) within the permeable formation to trap the drainage fluid within the pores of the permeable formation. In this embodiment, liquids from neighboring formations are permitted to enter as influx into the permeable formation as the plume of drainage fluid migrates within the permeable formation thereby serving to trap the drainage fluid within the pores of the permeable formation.

[0034] In an embodiment, at least some of the native liquid is produced from the permeable formation as the drainage fluid and / or the greenhouse gas are injected therein. For example, at least one production wellbore may extend between the permeable formation and the terranean surface at a location that is spaced from the injection wellbore through which the drainage fluid and greenhouse gas are injected. In this manner, native liquid of the permeable formation swept by the drainage fluid and / or the greenhouse gas flows from the permeable formation, uphole through the production wellbore, and from the production wellbore to the terranean surface. In this manner, at least a portion of the native liquid may be extracted from the permeable formation prior to and / or during the injection of greenhouse gas into the permeable formation. The production or takeoff of native liquid from the permeable formation to the terranean surface via a production wellbore may assist in minimizing the residual saturation of the permeable formation in at least some applications and depending upon the configuration of the respective permeable formation and injection wellbore used to inject the drainage fluid and / or greenhouse gas.

[0035] Referring now to Figure 1, an embodiment of a system 10 for storing a greenhouse gas 70 (shown in Figure 8) in a subterranean permeable formation 40 is shown. In some embodiments, greenhouse gas 70 comprises CO2. However, it may be understood, that greenhouse gas 70 may comprise greenhouse gases other than (or in addition to) CO2. As shown in Figure 1, permeable formation 40 is contained within a surrounding earthen subterranean formation 3 extending beneath a terranean surface 4. Terranean surface 4 may be a land surface, a sub-sea surface (e.g., a seabed), or other underwater surface. Additionally, it may be understood that subterranean formation 3 may comprise one or more permeable and impermeable layers or strata which are not shown in detail in Figure 1. Permeable formation 40 is permeable to the transmission of fluids (e.g., liquids, gasses, multi-phase fluids) therethrough and may be at least partially surrounded by one or more impermeable formations which may seal a pore space or volume of the permeable formation from the surrounding subterranean formation 3 such that at least some of the fluid present within permeable formation 40 remains trapped therein over an extended period of time (e.g., across a geological time scale). For example, in some instances, at least part of the periphery of permeable formation 40 may be surrounded by an impermeable cap rock layer of the subterranean formation 3 while another part of the periphery of the permeable formation 40 may be surrounded by a bedrock layer of the subterranean formation 3. In some embodiments, permeable formation 40 may fluidically communicate with a neighboring permeable formation (not shown in Figure 1) of the subterranean formation 3. However, in other embodiments, permeable formation 40 is entirely surrounded by impermeable formation(s) of subterranean formation 3. Additionally, it may be understood that the configuration of subterranean formation 3 may vary in other embodiments from that shown in Figure 1.

[0036] In this exemplary embodiment, system 10 generally includes surface assembly 12 located at the terranean surface 4 (assembly 12 may thus be referred to herein as “surface equipment”), a wellbore 20 extending generally vertically from the terranean surface 4 into the subterranean formation 3, and a casing string 30 extending through the wellbore 20.

[0037] In general, surface assembly 12 of system 10 may include any suitable equipment for supporting or facilitating transportation of fluids, tools, and / or other materials into and from the wellbore 20. In this exemplary embodiment, surface assembly 12 includes a support structure 14 (e.g., a well head, a casing string head) pressure control equipment 16 (e.g., one or more blowout preventers, surface valving including, e.g., one or more choke valves, one or more control valves) for controlling the flow rate of fluids into and from wellbore 20, and a fluid machine 18 (e.g., one or more reciprocating pumps, one or more rotary pumps, and / or one or more rotary compressors) fortransporting fluids (e.g., gasses, liquids, and / or multi-phase fluids) into and from wellbore 20.

[0038] Wellbore 20 of system 10 extends vertically (relative to the direction of gravity) from an uphole end located at the terranean surface 4 into the subterranean formation 3 along a central or longitudinal axis 25 and to a downhole end which penetrates and is positioned within the permeable formation 40 located beneath the terranean surface 4. In this configuration, wellbore 20 provides surface access to the permeable formation 40 located within the subterranean formation 3.

[0039] While wellbore 20 is shown in Figure 1 as substantially vertical, it should be appreciated that in other embodiments wellbore 20 may be deviated and extend at an incline relative to the direction of gravity along one or more sections of the deviated wellbore. Additionally, wellbore 20 may be formed with various dimensions (diameter) and depths. It may also be understood that wellbore 20 is formed using a drilling system not shown in Figure 1 which may include, among other things, a support structure (e.g., a derrick, a mast) located at the terranean surface 4, and a drilling assembly deployable into the subterranean formation 3 including a drill bit for cutting into the subterranean formation and which is coupled to a downhole end of a drill string suspended from the surface support structure.

[0040] Casing string 30 of system 10 extends axially from a first or uphole end located proximate to terranean surface 4 (e.g. coupled to surface assembly 12) into wellbore 20. Casing string 30 is secured to a generally cylindrical sidewall of wellbore 20 via cement (or any other suitable material that has been pumped into the annulus formed between an outer surface of casing string 30 and the sidewall of wellbore 20). In this configuration, a flow path is formed along a central passage 31 of casing string 30 that extends from the terranean surface 4 and into the permeable formation 40. In some embodiments, casing string 30 may comprise a plurality of steel casing string joints that are coupled end-to-end and installed in the wellbore 20 via a drilling system not shown in Figure 1. It may be understood that in other embodiments the casing string 30 may terminate uphole from the permeable formation 40. In other embodiments, system 10 may not include casing string 30 and wellbore 20 may instead comprise an uncased wellbore. In still other embodiments, the casing string 30 may be perforated to facilitate the flow of fluids in and out of the permeable formation 40 into the wellbore 20.

[0041] Figure 1 illustrates a system in a first or initial state in which the permeable formation 40 is at least partially saturated by a native liquid 42 of the permeable formation 40. The saturation of permeable formation 40 by native liquid 42 (e.g., water, brine, hydrocarbons) corresponds to an initial saturation of the permeable formation 40 by the native liquid 42 when system 10 is in the initial state. The permeable formation 40 may comprise a porous structure with the native liquid 42 at least partially saturating the pores of the permeable formation 40. In some embodiments, permeable formation 40 comprises an aquifer such as a saline aquifer. However, in other embodiments, permeable formation 40 may comprise other permeable subsurface structures including, for example, sandstones, carbonates, and the like.

[0042] To provide an example, and referring to Figure 2, permeable formation 40 is defined by a plurality of grains 44 (e.g., sand grains) having openings formed therebetween which define a plurality of pores 46 of the permeable formation 40. As shown in Figure 2, The plurality of pores 46 are interconnected three dimensionally (3D) to allow fluid flow within and through the permeable formation 40. In this exemplary embodiment, the pores 46 of permeable formation 40 are approximately entirely saturated with the native liquid 42. In other words, the initial saturation of permeable formation 40 by native liquid 42 is approximately 100% in this exemplary embodiment. In other embodiments, the initial saturation of permeable formation 40 by native liquid 42 may be less than 100% (e.g., 70% or greater). For example, the permeable formation 40 may be initially at least partially saturated by a native gas which may be immiscible with the native liquid 42. Additionally, the structure of permeable formation 40 may vary in other embodiments from the structure (e.g., the formation of grains 44 and corresponding pores 46) shown in Figure 2.

[0043] Referring now to Figures 3 and 4, Figure 3 illustrates the system 10 in a second or drainage state in which a drainage fluid (indicated by arrow 50 in Figure 3) is injected from the surface assembly 12, through the central passage 31 of casing string 30, and into the permeable formation 40. The drainage fluid 50 may comprise carbon dioxide (CO2) and / or any other gas that is miscible with CO2 such as greenhouse gas 70. In some embodiments, the drainage fluid 50 is injected into the permeable formation 40 under conditions suitable for inducing the flow of drainage fluid 50 from the wellbore 20 into the permeable formation 40. For example, injecting the drainage fluid 50 into the permeable formation 40 may include selecting a proper density of the drainage fluid 50 and injecting the drainage fluid 50 into the permeable formation 40 at a predefined pressure (e.g., as controlled by the fluid machine 18 of surface assembly 12) that is greater than a pore pressure of the permeable formation 40 but less than a fracture pressure of the permeable formation 40. For example, in some embodiments, the ratio of the density of native liquid 42 to the density of drainage fluid 50 is less than about 2.2. In other embodiments, the ratio of the density of native liquid 42 to the density of drainage fluid 50 is less than about 2.0. In still other embodiments, the ratio of the density of native liquid 42 to the density of drainage fluid 50 is less than about 1.8.

[0044] In some embodiments, injecting the drainage fluid 50 into the permeable formation 40 may comprise injecting a predefined volume of the drainage fluid 50 into the permeable formation 40 over a predefined period of time. For example, in some embodiments, the drainage fluid 50 may be injected into the permeable formation 40 at a rate of 0.5-2 million tons per year (ton / yr). In other embodiments, the drainage fluid 50 may be injected into the permeable formation 50 at a rate of 1.5-1 ton / yr.

[0045] In some embodiments, the fluid machine 18 comprises one or more compressors which may be used to inject the drainage fluid 50 into the permeable formation 40. As shown in Figure 4, the drainage fluid 50 injected into the permeable formation 40 migrates within and through pores 46 saturated by the native liquid 42. In some embodiments, the injection of drainage fluid 50 into the permeable formation 40 sweeps some of the native liquid 42 from the permeable formation 40 whereby the swept native liquid 42 may enter a neighboring permeable formation and / or a production well.

[0046] Referring to Figures 5 and 6, Figure 5 illustrates the system 10 in a third or trapped drainage fluid state in which the permeable formation 40 is flooded with an imbibition liquid 60 following injection of the drainage fluid 50 to trap the drainage fluid 50 (shown as trapped drainage fluid bubbles 52 in Figure 6) within the pores 46 of the permeable formation 40. In this exemplary embodiment, the imbibition liquid 60 is injected from the surface assembly 12 (e.g., via the fluid machine 18), through the central passage 31 of casing string 30, and into the permeable formation 40. The imbibition liquid 60 is miscible with the native liquid 42 of the permeable formation 40. As described above, both the native liquid 42 and the imbibition liquid 60 may comprise water (e.g., brine). As shown in Figure 6, the imbibition liquid 60 mixes with the native liquid 42 and is absorbed into the pores 46 of the permeable formation 40 as a result of capillary forces and displacement forces acting in the pores 46 of the permeable formation 40. In particular, the imbibition liquid 60 migrates into the pores 46 of the permeable formation 40 thereby creating pockets of trapped drainage fluid 50 (e.g., drainage fluid bubbles 52) in the pores 46 of the permeable formation 40 which forms a 2-phase structure with the drainage fluid bubbles 52 dispersed within the surrounding liquid mixture 45 of native liquid 42 and imbibition liquid 60. In this manner, the drainage fluid 50 is trapped within the pores 46 of the permeable formation 40 as drainage fluid bubbles 52 thereby reducing the initial native liquid 42 saturation of the permeable formation 40. In some embodiments, typical trapped gas saturations range between approximately 20-55% for a typical rock having a porosity of 15-25%.

[0047] In some embodiments, injecting the imbibition liquid 60 into the permeable formation 40 comprises injecting a predefined volume of the imbibition liquid 60 into the permeable formation 40 over a predefined period of time.

[0048] Referring to Figures 7 and 8, Figure 7 illustrates the system 10 in a fourth or sequestration state in accordance with principles disclosed herein. As described above, a greenhouse gas 70 is injected from the surface assembly 12, through the central passage 31 of casing string 30, and into the permeable formation 40 via the operation of one or more compressors comprising the fluid machine 18. As shown in Figure 8, as the greenhouse gas 70 is injected into the permeable formation 40, at least a portion of the liquid mixture 45 and the drainage fluid 50 are displaced or swept by the greenhouse gas 70 such that at least some of the pores previously occupied by the liquid mixture 45 and / or drainage fluid 50, and the native liquid 42 is now occupied by the greenhouse gas 70. In this manner, the volume of greenhouse gas 70 stored in the permeable formation 40 is maximized. In some embodiments, at least some of the liquid mixture 45, and the drainage fluid 50 may be swept from the permeable formation 40 into a neighboring subterranean formation to which the permeable formation is fluidically connected and / or a production well.

[0049] The injection of greenhouse gas 70 into permeable formation 40 further reduces the saturation (from the saturation of the imbibition state of system 10) of permeable formation 40 by the native liquid 42, maximizing the volume of greenhouse gas 70 that may be stored within the permeable formation 40. By reducing the saturation of the permeable formation 40 by the native liquid 42 first using the drainage fluid 50 and imbibition liquid 60, the final or remaining liquid saturation of the permeable formation 40 (corresponding to the sequestration state of system 10) may be minimized. In some embodiments, the secondary drainage resulting from injecting the drainage fluid 50, and imbibition liquid 60 prior to injecting the greenhouse gas 70, may result in approximately 80-60% reduction in the remaining liquid saturation of permeable formation 40, compared to approximately 50-40% reduction by primary drainage i.e. without injecting drainage fluid 50, nor the imbibition liquid 60, only injecting the greenhouse gas 70.

[0050] Referring now to Figure 9, an exemplary graph 100 is shown illustrating the relationship (indicated by curve 102 of graph 100) between final or remaining liquid saturation along the Y-axis of graph 100 and initial liquid saturation in a subterranean permeable formation (e.g., permeable formation 40). As depicted in curve 102 of Figure 9, the remaining liquid saturation increases asymptotically with increasing initial liquid saturation. Thus, if the permeable formation 40 begins with a high initial liquid saturation (e.g., from the native liquid 42 for permeable formation 40), the residual liquid saturation of the permeable formation will generally be greater than in instances in which the permeable formation begins with a relatively lower initial liquid saturation. It should be noted that the relationship between remaining liquid saturation and initial liquid saturation is a function of the properties of the permeable formation including porosity, permeability, grain size distribution, pore throat size distribution, interfacial tension between fluids, and wettability of the rock / fluid system.

[0051] Referring to Figure 10, a schematic illustration of another embodiment of a greenhouse gas sequestration system 200 is shown in accordance with principles disclosed herein. In this exemplary embodiment, system 200 includes, along with wellbore 20 which comprises an injection wellbore 20 in this embodiment, at least one production wellbore 220 extending between the permeable formation 40 and the terranean surface 4 at a location that is spaced along the terranean surface 4 from the injection wellbore 20 through which the drainage fluid 50 and greenhouse gas 70 are injected.

[0052] System 200 additionally includes a surface assembly 212 located at the terranean surface 4, the production wellbore 220 extending generally vertically from the terranean surface 4 into the subterranean formation 3, and a casing string 230 extending through the production wellbore 220. In general, surface assembly 212 of system 200 may include any suitable equipment for supporting or facilitating transportation of fluids from the wellbore 220. In this exemplary embodiment, surface assembly 212 includes a support structure 214 (e.g., a well head, a casing string head) pressure control equipment 216 for controlling the flow rate of fluids into and from wellbore 220, and a second fluid machine 218 for transporting fluids (e.g., gasses, liquids, and / or multi-phase fluids) from wellbore 220.

[0053] Production wellbore 220 of system 200 extends vertically from an uphole end located at the terranean surface 4 into the subterranean formation 3 along a central or longitudinal axis and to a downhole end which penetrates and is positioned within the permeable formation 40 located beneath the terranean surface 4. In this configuration, production wellbore 220 fluidically communicates with and provides surface access (along with injection wellbore 20) to the permeable formation 40 located within the subterranean formation 3. While production wellbore 220 is shown in Figure 10 as substantially vertical, it should be appreciated that in other embodiments wellbore 220 may be deviated and extend at an incline relative to the direction of gravity along one or more sections of the deviated wellbore. Additionally, wellbore 220 may be formed with various dimensions (diameter) and depths.

[0054] Casing string 230 of system 200 extends axially from a first or uphole end located proximate to terranean surface 4 (e.g. coupled to surface assembly 212) into wellbore 220. Casing string 230 is secured to a generally cylindrical sidewall of production wellbore 220 via cement (or any other suitable material that has been pumped into the annulus formed between an outer surface of casing string 230 and the sidewall of production wellbore 220). In this configuration, a flow path is formed along a central passage 231 of casing string 230 that extends from the terranean surface 4 and into the permeable formation 40. In some embodiments, casing string 230 may comprise a plurality of steel casing string joints that are coupled end-to-end and installed in the production wellbore 220 via a drilling system not shown in Figure 10. It may be understood that in other embodiments the casing string 230 may terminate uphole from the permeable formation 40. In other embodiments, system 200 may not include casing string 230 and production wellbore 220 may instead comprise an uncased wellbore. In still other embodiments, the casing string 230 may be perforated to facilitate the flow of fluids from the permeable formation 40 into the production wellbore 220.

[0055] As described above, the drainage fluid 50 may be injected into the permeable formation 40 through injection wellbore 20 prior to injecting the greenhouse gas 70 into the permeable formation 40. The drainage fluid 50 displaces the native liquid 42 of the permeable formation 40. Thus, at least some of the native liquid 42 of the permeable formation 40 is swept (indicated by arrow 201 in Figure 10) by the drainage fluid 50 and flows from the permeable formation 40, uphole through the production wellbore 220, and from the production wellbore 220 to the terranean surface 4 into a surface tank 211 of system 200. In this manner, at least a portion of the native liquid 42 may be extracted from the permeable formation 40 prior to and / or during the injection of greenhouse gas 70 into the permeable formation 40. The production or takeoff of native liquid 42 from the permeable formation 40 to the terranean surface 4 via production wellbore 220 may assist in minimizing the remaining liquid saturation of the permeable formation 40 in at least some applications depending upon the configuration of the respective permeable formation 40 and injection wellbore 20 used to inject the drainage fluid 50 and / or greenhouse gas 70. In some embodiments, at least a portion of the drainage fluid 50 may also be displaced and produced at the terranean surface 4 through the production wellbore 220 while the greenhouse gas 70 is injected through wellbore 20 into the permeable formation 40.

[0056] Referring now to Figure 11, a schematic illustration of another embodiment of a greenhouse gas sequestration system 300 is shown in accordance with principles disclosed herein. In this exemplary embodiment, a portion of the top of permeable formation 40 is bounded by impermeable cap rock layer 5 of the subterranean formation 3. In some embodiments, the impermeable cap rock 5 may comprise faults creating a pathway for fluid flow in and out of subterranean formation 3 to neighboring permeable formations. In other embodiments, permeable formation 40 may be enclosed laterally by impermeable cap rock 5, but overlain and / or underlain by a semi-permeable formation. In this exemplary embodiment, system 300 generally includes a surface assembly (not shown) located at the terranean surface 4, and a wellbore 320 extending generally vertically from the terranean surface 4 into the subterranean formation 3.

[0057] As described above, the saturation of the permeable formation 40 by the native liquid 42 is first artificially reduced prior to injecting the greenhouse gas 70 into the permeable formation 40 by injecting a drainage fluid 50 into the permeable formation 40 through wellbore 320. After a predefined period of time, a plume of the drainage fluid 50 (in the form of drainage fluid bubbles 355) begins to migrate (depicted by line 371 in Figure 11) through permeable formation 40 forming an accumulation 372 within the permeable formation 40 at the top thereof. In this exemplary embodiment, liquids from neighboring formations are permitted to enter (e.g., through the faults in the impermeable cap rock 5) into the permeable formation 40 as the plume of drainage fluid 50 migrates within the permeable formation 40 thereby serving to trap the drainage fluid 50 within the pores 46 of the permeable formation 40. Further, the native liquid 42 of the permeable formation 40 is permitted to flow into neighboring formations thereby reducing the initial saturation of the permeable formation 40 while maximizing the volume of greenhouse gas 70 which may be stored within permeable formation 40. In some embodiments, as the drainage fluid 50 is injected, at least some of the drainage fluid 50 will be absorbed into the native liquid 42 of the permeable formation 40 until the native liquid 42 is saturated with the drainage fluid 50. Beyond saturation, some of the saturated native liquid may drop off (depicted by 373 in Figure 11). In some embodiments, the saturated native liquid 373 may be more dense than the native liquid 42.

[0058] A predefined volume of greenhouse gas 70 may be injected into the permeable formation 40 following the injection of the drainage fluid 50 at a predefined rate, and following imbibition brine, and at a predefined pressure that is greater than a pore pressure of the permeable formation 40 but less than a fracture pressure of the permeable formation 40. The injected greenhouse gas 70 takes up the pores 46 previously occupied by the native liquid 42, thereby maximizing the volume of greenhouse gas 70 that is stored.

[0059] Referring now to Figure 12 and 13, depleted or depleting oil fields can be advantageously utilized for storing carbon dioxide and / or other greenhouse gasses when the economic limit of the field has been reached either by primary recovery mechanisms or by secondary / tertiary recovery methods (e.g., CO2 or steam enhanced oil recovery).

[0060] Figure 12 is a schematic illustration of another embodiment of a greenhouse gas sequestration system 400 in accordance with principles disclosed herein. In this exemplary embodiment, system 400 generally includes depleted wellbore 419 (e.g., a depleted production wellbore 419) and an injection wellbore 420 extending generally vertically from the terranean surface 4 into the subterranean formation 3. In some embodiment, depleted wellbore 419 may extend generally between the permeable formation 40 and the terranean surface 4 at a location that is spaced along the terranean surface 4 from the injection wellbore 420. In some embodiments, depleted wellbore 419 may comprise a plugged well in a permeable formation 40 that is located in a depleted field. In some embodiments, the permeable formation 40 may have a remaining oil saturation based on remaining natural gas 80 from primary or secondary / tertiary recovery mechanisms.

[0061] In some embodiments, the saturation of the permeable formation 40 by the native liquid 42 is first artificially reduced prior to injecting the greenhouse gas 70 into the permeable formation 40 by injecting a drainage fluid 50 into the permeable formation 40 through wellbore 420 to further reduce the initial saturation of the permeable formation 40 prior to injection of the greenhouse gas 70 into the permeable formation 40. After a predefined period of time, a plume of the drainage fluid 50 migrates through the permeable formation 40 (depicted by line 471 in Figure 12) forming a dome structure 472 at the top of the permeable formation 40 above the existing gas cap 473 formed by the remaining natural gas 80 in the permeable formation 40.

[0062] Referring now to Figure 13, a schematic illustration of another embodiment of a greenhouse gas sequestration system 500 is shown in accordance with principles disclosed herein. In this exemplary embodiment, system 500 generally includes a depleted wellbore 519 and injection wellbore 520. In some embodiments, depleted wellbore 519 may extend generally between the permeable formation 40 and the terranean surface 4 at a location that is spaced along terranean surface 4 from the wellbore 520. In some embodiments, the permeable formation 40 may be located in a depleted field where the permeable formation 40 has a remaining oil saturation based on the remaining natural gas 80 from primary or secondary / tertiary recovery mechanisms.

[0063] As described above, the saturation of the permeable formation 40 by the native liquid 42 is first artificially reduced prior to injecting the greenhouse gas 70 into the permeable formation 40 by injecting a drainage fluid 50 into the permeable formation 40 through wellbore 520. In this embodiment, the injected drainage fluid 50 begins to migrate within the permeable formation 40 as the permeable formation 40 is being depleted, thereby trapping the drainage fluid 50 within the pores 46 of the permeable formation 40.

[0064] Referring to Figure 14, a schematic illustration of another embodiment of a greenhouse gas sequestration system 600 is shown in accordance with principles disclosed herein. In this exemplary embodiment, the permeable formation 40 comprises a heterogeneous reservoir 7 comprising a plurality of flat reservoir seal interfaces 8. In this exemplary embodiment, plume geometry may be highly complex as depicted by flow path 609 in Figure 14. Particularly, different sweep paths may be engineered such that the greenhouse gas 70 passes through an initial drainage fluid zone, depending on well placement in the heterogenous reservoir 7.

[0065] Referring now to Figure 15, a schematic illustration of another embodiment of a greenhouse gas sequestration system 700 is shown in accordance with principles disclosed herein. In this exemplary embodiment, a vertically upper end or top of the permeable formation 40 is bounded by an impermeable cap rock layer 5 of the subterranean formation 3 forming a dome-shaped roof of the permeable formation 40. In some embodiments, a vertically lower end or bottom of the permeable formation 40 may be surrounded by a bedrock layer of the subterranean formation 3. In this manner, a closed system is formed whereby the permeable formation 40 is blocked vertically by the impermeable cap rock layer 5, forming an impervious seal around the top of the permeable formation 40. In this exemplary embodiment, system 700 generally includes surface assembly (not shown) located at the terranean surface 4, and a wellbore 720 extending generally vertically from the terranean surface 4 into the subterranean formation 3.

[0066] As described above, the saturation of the permeable formation 40 by the native liquid 42 is first artificially reduced prior to injecting the greenhouse gas 70 into the permeable formation 40 by injecting a drainage fluid 50 into the permeable formation 40 through wellbore 720. The drainage fluid 50 may become trapped within pores of the permeable formation 40 as drainage fluid bubbles 755. After a predefined period of time, a plume of the drainage fluid 50 begins to migrate vertically upwards (depicted by line 771 in Figure 15) forming a dome structure 772 at the top of the permeable formation 40 to trap the drainage fluid 50 within the pores 46 of the permeable formation 40 and minimizing the final or residual liquid saturation of the permeable formation 40 and thereby maximizing the storage capacity (e.g., with respect to storing greenhouse gasses) of the permeable formation 40.

[0067] Particularly, a predefined volume of greenhouse gas 70 may be injected into the permeable formation 40 following the injection of the drainage fluid 50, at a predefined rate, and at a predefined pressure that is greater than a pore pressure of the permeable formation 40 but less than a fracture pressure of the permeable formation 40. The injected greenhouse gas 70 takes up the pores 46 previously occupied by the native liquid 42, thereby maximizing the volume of greenhouse gas 70 that is stored. Pressure build up over time may be taken into consideration to preserve the integrity of the system.

[0068] Referring to Figure 16, a flowchart of an embodiment of a method 800 for storing a greenhouse gas (e.g., greenhouse gas 70 shown in Figure 7) in a subterranean permeable formation (e.g., permeable formation 40 shown in Figures 1-8) containing a native liquid (e.g., native liquid 42 shown in Figures 1-8) is shown in accordance with principles disclosed herein. Initially, at block 802, method 800 comprises injecting a drainage fluid (e.g., drainage fluid 50 shown in Figures 3 and 4) into the permeable formation via at least one wellbore (e.g., wellbore 20 shown in Figures 1, 3, 5, and 7) extending from the terranean surface (e.g., terranean surface 4 shown in Figures 1,3, 5, and 7) and penetrating the permeable formation to increase a gas saturation of the permeable formation. At block 804, method 800 comprises injecting, following the injection of the drainage fluid into the permeable formation, a greenhouse gas into the permeable formation via the at least one wellbore to store at least a portion of the greenhouse gas within the permeable formation.

[0069] Referring to Figure 17, a flowchart of another embodiment of a method 820 for storing a greenhouse gas (e.g., greenhouse gas 70 shown in Figure 7) in a subterranean permeable formation (e.g., permeable formation 40 shown in Figures 1-8) containing a native liquid (e.g., native liquid 42 shown in Figures 1-8) is shown in accordance with principles disclosed herein. Initially, at block 822, method 820 comprises injecting a drainage fluid (e.g., drainage fluid 50 shown in Figures 3 and 4) into the permeable formation via at least one wellbore (e.g., wellbore 20 shown in Figures 1, 3, 5, and 7) extending from the terranean surface (e.g., terranean surface 4 shown in Figures 1,3, 5, and 7) and penetrating the permeable formation to increase a gas saturation of the permeable formation. At block 824, method 820 comprises injecting, following the injection of the drainage fluid into the permeable formation, a greenhouse gas into the permeable formation via the at least one wellbore to store at least a portion of the greenhouse gas within the permeable formation. At block 824, method 820 comprises discharging, in response to at least one of the injection of the drainage fluid and the greenhouse gas into the permeable formation, the native liquid from the permeable formation into at least on production wellbore extending from the permeable formation to the terranean surface.

[0070] Referring to Figure 18, a flowchart of another embodiment of a method 840 for storing a greenhouse gas (e.g., greenhouse gas 70 shown in Figure 7) in a subterranean permeable formation (e.g., permeable formation 40 shown in Figures 1-8) containing a native liquid (e.g., native liquid 42 shown in Figures 1-8) is shown in accordance with principles disclosed herein. Initially, at block 842, method 840 comprises injecting a drainage fluid (e.g., drainage fluid 50 shown in Figures 3 and 4) into the permeable formation via at least one wellbore (e.g., wellbore 20 shown in Figures 1, 3, 5, and 7) extending from the terranean surface and penetrating the permeable formation to increase a gas saturation of the permeable formation. At block 844, method 840 comprises injecting, following the injection of the drainage fluid into the permeable formation, an imbibition liquid (e.g., imbibition liquid shown in Figure 5) into the permeable formation via the at least one wellbore to trap at least some of the drainage fluid within pores of the permeable formation. At block 846, method 840 comprises injecting, following the injection of the imbibition liquid into the permeable formation, the greenhouse gas into the permeable formation via the at least one wellbore to store at least a portion of the greenhouse gas within the permeable formation.

[0071] While disclosed embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

Claims

1. A method for storing a greenhouse gas in a subterranean permeable formation positioned beneath a terranean surface and containing a native liquid, the method comprising:(a) injecting a drainage fluid into the permeable formation via at least one wellbore extending from the terranean surface and penetrating the permeable formation to increase a gas saturation of the permeable formation whereby at least a portion of the injected drainage fluid is trapped within pores of the permeable formation; and(b) injecting, following (a), the greenhouse gas into the permeable formation via the at least one wellbore to store at least a portion of the greenhouse gas within the permeable formation.

2. The method of claim 1, wherein the permeable formation comprises a saline aquifer.

3. The method of claim 1 or 2, wherein the drainage fluid comprises carbon dioxide.

4. The method of any preceding claim, wherein the greenhouse gas comprisescarbon dioxide.

5. The method of any preceding claim, wherein the drainage fluid is injected into the permeable formation at a rate of 0.5-2 million tons per year (ton / yr).

6. The method of any preceding claim, further comprising:(c) injecting an imbibition liquid into the permeable formation via the at least one wellbore to trap at least some of the drainage fluid within pores of the permeable formation.

7. The method of any preceding claim, wherein (a) comprises drainage fluid into the permeable formation at a predefined pressure which is greater than a pore pressure of the permeable formation but less than a fracture pressure of the permeable formation.

8. The method of any preceding claim, wherein, the at least one wellbore comprises an injection well having an inlet at the terranean surface for injecting a fluid into the wellbore, and an outlet within the permeable formation for injecting the fluid into the permeable formation.

9. A method of storing a greenhouse gas in a subterranean permeable formation positioned beneath a terranean surface and containing a native liquid, the method comprising:(a) injecting a drainage fluid into the permeable formation via at least one injection wellbore extending from the terranean surface and penetrating the permeable formation to increase a gas saturation of the permeable formation;(b) injecting, following (a), the greenhouse gas into the permeable formation via the at least one injection wellbore to store at least a portion of the greenhouse gas within the permeable formation; and(c) discharging, in response to at least one of (a) and (b), the native liquid from the permeable formation and into at least one production wellbore extending from the permeable formation to the terranean surface.

10. The method of claim 9, wherein the permeable formation comprises a saline aquifer and the native liquid comprises brine.

11. The method of claim 9 or 10, wherein the greenhouse gas comprises carbon dioxide.

12. The method of any of claims 9 to 11, wherein the drainage fluid comprises carbon dioxide.

13. The method of any of claims 9 to 12, further comprising:(d) injecting, following (a), an imbibition liquid into the permeable formation via the at least one wellbore to trap at least some of the drainage fluid within pores of the permeable formation.

14. The method of claim 13, wherein the imbibition liquid comprises water.

15. A method for storing a greenhouse gas in a subterranean permeable formation positioned beneath a terranean surface and containing a native liquid, the method comprising:(a) injecting a drainage fluid into the permeable formation via at least one wellbore extending from the terranean surface and penetrating the permeable formation to increase a gas saturation of the permeable formation;(b) injecting, following (a), an imbibition liquid into the permeable formation via the at least one wellbore to trap at least some of the drainage fluid within pores of the permeable formation; and(c) injecting, following (b), the greenhouse gas into the permeable formation via the at least one wellbore to store at least a portion of the greenhouse gas within the permeable formation.

16. The method of claim 15, wherein the imbibition liquid comprises water.

17. The method of claim 15 or 16, wherein the permeable formation comprises a saline aquifer.

18. The method of any of claims 15 to 17, wherein the greenhouse gas comprises carbon dioxide.

19. The method of any of claims 15 to 18, wherein the drainage fluid comprises carbon dioxide.

20. The method of any of claims 15 to 19, further comprising:(d) discharging, in response to at least one of (a), (b), and (c), the native liquid from the permeable formation and into at least one production wellbore extending from the permeable formation to the terranean surface.

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